ML103270413
| ML103270413 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 11/04/2010 |
| From: | Repko R Duke Energy Carolinas |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| DUK103080023 | |
| Download: ML103270413 (101) | |
Text
DISPOSITION OF THE ORIGINAL DOCUMENT WILL BE TO PRIORITY Normal THE TRANSMITTAL SIGNATURE UNLESS RECIPIENT IS Date: 11104/10 OTHERWISE IDENTIFIED BELOW Document Transmittal #: DUK103080023
- 1) 01820 J R ELKINS- ECO81
- No
- 3) 02532 RESIDENT NRC INSPECTOR MG01VP
- 4) 02546 WC LIBRARY - MG01WC DOCUMENT TRANSMITTAL FO OTHER ACKNOWLEDGEMENT REQUIRED
- 5) 03044 MCG DOC CNTRL MISC MAN MG05DM ACKNOWLEDGE RECEIPT BY RETURNING THIS FORM TO:
REFERENCE
- 8) 03744 OPS TRNG MGR. MG03OT McGuire
- 9) 03759 U S NUC REG WASHINGTON, DC DCRM MGO2DM TECHNICAL SPECIFICATIONS (TS)
- 10) 03796 SCIENTECH DUNEDIN, FL 13225 Hagers Ferry Road
- 11) 04698 D E BORTZ EC08G TECHNICAL SPECIFICATIONS Huntersville, N.C. 28078
- 12) 04809 MCG PLANT ENG. LIBR. MG05SE BASES (TSB)
- 13) 04834 LINDA KDAVILA MG01RP
- 14) 05262 J L FREEZE MG011E
- 15) 05606 J C MORTON MGO1 EP Rec'd By Page 2 of 3 Date DOCUMENT NO QACOND REV #/DATE DISTR CODE 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 TOTAL i i -+ I- F I- I- I ~- I + I- I V F F + + +
MEMO NA - 10/21/10 MADM-04B V1 vi V1 V3 V8 V1 V1 V2 vi vi 42 UNIT #1 FOL NA --- 10/21/10 UNIT #2 FOL NA --- 10/21/10 TS LIST OF EFFECTIVE PAGES NA 089 10/21/10 TS 3.6.6-2 AMEND 259/239 / NA ----10/21/10 TSB LIST OF EFFECTIVE SECTIONS V/ NA 103 10/21/10 TSB 2.1.2 V NA 109 10/21/10 TSB 3.6.10 NA 109 10/21/10 TBS 3.7.9( NA 109 10/21/10 TBS 3.7.11 v NA 109 10/21/10 TSB 3.6.6/ NA 110 10/21/09 TSB 3.8.1 / NA 111 10/21/10 REMARKS: PLEASE UPDATE ACCORDINGLY. R T REPKO PLEASE PLACE UNIT #1 FOL AND UNIT #2 FOL IN THE FRONT OF YOUR TECH SPEC BOOK. VICE PRESIDENT MCGUIRE NUCLEAR STATION BY:
B C BEAVER MG01RC BCB/TLC
October 21. 2010 MEMORANDUM To: All McGuire Nuclear Station Technical Specification (TS) and Tech Spec Bases (TSB) Manual Holders
Subject:
McGuire TS and TSB Updates /
Attention: Facility Operating License (FOL) Included Included in this distribution is an updated copy of the Unit I and Unit 2 FOL. Please place the updated copies in the front of your Technical Specification book. Please recycle your old copies. The FOL was updated to reflect Amendment 259/239.
REMOVE INSERT TS Manual TS LOEP (Revision 88) TS LOEP (Revision 89)
TS 3.6.6-2 TS 3.6.6-2 Amendment 259/239 TS Bases Manual TSB LOES (Revision 102) TSB LOES (Revision 103)
TSB 2.1.2 (entire document) TSB 2.1.2 (Revision 109)
TSB 3.6. 10 (entire document) TSB 3.6.10 (Revision 109)
TSB 3.7.9 (entire document) TSB 3.7.9 (Revision 109)
TSB 3.7.11 (entire document) TSB 3.7.11 (Revision 109)
TSB 3.6.6 (entire document) TSB 3.6.6 (Revision I10)
TSB 3.8.1 (entire document) TSB 3.8.1 (Revision I11)
Revision numbers may skip numbers due to Regulatory Compliance Filing System.
Please call me if you have questions.
Bonnie Beaver Regulatory Compliance 875-4180
DUKE ENERGY CAROLINAS, LLc DOCKET NO. 50-369 MCGUIRE NUCLEAR STATION, UNIT 1 RENEWED FACILITY OPERATING LICENSE Renewed License No. NPF-9
- 1. The U.S. Nuclear Regulatory Commission (Commission), having previously made the findings set forth in License No. NPF-9 issued on June 12, 1981, has now found that:
A. The application for renewed operating license filed by the Duke Energy Corporation* complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in' 10 CFR Chapter I and all required notifications to other agencies or bodies have, been duly made; B. Actions have been identified and have been or will be taken with respect to (1) managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21 (a)(1), and (2) time-limited aging analyses that have been identified to require review under 10 CFR 54.,21 (c), such that there is reasonable assurance that the activities authorized by the renewed operating license will continue to be conducted in accordance with the current licensing basis, as defined in 10 CFR 54.3, for the McGuire Nuclear Station, Unit 1 (facility or plant), and that any changes made to the plant's current licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the Act and the Commission's regulations;-
C. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission; D. There is reasonable assurance: (i) that the activities authorized by this renewed operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; E. The licensee is technically and financially qualified to engage in the activities authorized by this renewed operating license in accordance with the Commission's regulations set forth in 10 CFR Chapter I; Duke Energy Corporation converted to Duke Power Company LLC on April 3, 2006 and was re-named Duke Energy Carolinas, LLC as of October 1, 2006. Duke Energy Carolinas, LLC is the owner and operator of McGuire Nuclear Station, Unit 1. References to the "licensee" or "Duke" are to Duke Energy Carolinas, LLC.
Renewed License No. NPF-9 Amendment No. 245
F. The licensee has satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements," of the Commission's regulations; G. The issuance of this renewed operating license will not be inimical to the common defen se and securityor-to-the health--and-safety of-the- public; H. After weighing the environmental, economic, technical, and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of this Renewed Facility Operating License No. NFP-9 is in accordance with 10 CFR Part 51, of the Commission's regulations and all applicable requirements have been satisfied; and, I. The receipt, possession, and use of source, byproduct and special nuclear material as authorized by this renewed operating license will be in accordance with the Commission's regulations in 10 CFR Parts 30, 40 and 70.
- 2. Based on the foregoing findings, and pursuant to approval by the Nuclear Regulatory Commission at a meeting on June 9, 1981, the License for Fuel-Loading and Zero Power Testing issued on January 23, 1981, as amended, is superseded by Renewed Facility Operating License No. NPF-9 which is hereby issued to Duke Energy Carolinas, LLC to read as follows:
A. This renewed operating license applies to the McGuire Nuclear Station, Unit 1, a pressurized water reactor and associated equipment (the facility) owned and operated by Duke Energy Carolinas, LLC. The facility is located on the licensee's site in Mecklenburg County, North Carolina, on the shore of Lake Norman approximately 17 miles northwest of Charlotte, North Carolina and is described in the Updated Final Safety Analysis Report, as supplemented and amended, and in the Environmental Report, as supplemented and amended.
B. Subject to the conditions and requirements incorporated herein, the Commission hereby licenses Duke Energy Carolinas, LLC:
(1) Pursuant to Section 103 of the Act and 10 CFR Part 50, to possess, use, and operate the facility at the designated location in Mecklenburg County, North Carolina, in accordance with the procedures and limitations set forth in the renewed operating license; (2) Pursuant to the Act and 10 CFR Part 70 to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended; (3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70 to receive, possess and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; Renewed License No. NPF-9 Amendment No. 245
(4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as may be produced by the operation of McGuire Nuclear Station, Units 1 and 2, and; (6) Pursuant to the Act and 10 CFR Parts 30 and 40, to receive, possess and process for release or transfer such byproduct material as may be produced by the Duke Training and Technology Center.
C. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:
(1) Maximum Power Level The licensee is authorized to operate the facility at a reactor core full steady state power level of 3411 megawatts thermal (100%).
(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 259, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.
(3) Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation.
Duke shall complete these activities no later than June 12, 2021, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.
The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71 (e)(4), following issuance of this renewed operating license.
Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.
Renewed License No. NPF-9 Amendment No. 259
(4) Fire Protection Program Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility and as approved in the SER dated--March 1978 and Supplements-2, 5-and--6 -dated-March-1979, April 1981, and February 1983, respectively, and the safety evaluation dated May 15, 1989, subject to the following provision:
Duke may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.
(5) Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 200, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.
(6) Antitrust Conditions The licensee shall comply with the antitrust conditions delineated in Appendix C of this renewed operating license.
(7) Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:
A) Fire fighting response strategy with the following elements:
- 1. Pre-defined coordinated fire response strategy and guidance
- 2. Assessment of mutual aid fire fighting assets
- 3. Designated staging areas for equipment and materials
- 4. Command and control
- 5. Training of response personnel B) Operations to mitigate fuel damage considering the following:
- 1. Protection and use of personnel assets
- 2. Communications
- 3. Minimizing fire spread
- 4. Procedures for implementing integrated fire response strategy
- 5. Identification of readily-available pre-staged equipment
- 6. Training on integrated fire response strategy
- 7. Spent fuel pool mitigation measures C) Actions to minimize release to include consideration of:
- 1. Water spray scrubbing
- 2. Dose to onsite responders Renewed License No. NPF-9 Amendment No. 245
-4A-D. Physical Protection Duke Energy Carolinas, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made
.-pursu-at--to provisionsg of the MiscellaneousAmendments and- Search .
Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on September 30, 2004, October 15, 2004, October 21, 2004, and October 27, 2004.
E. Deleted by Amendment No. 233.
Renewed License No. NPF-9 Amendment No. 245
F. The licensee shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.
-G-.- Th-e-li-ehee-is authdrized to r ecive-from-the Oconee Nuclear -Station,-Units-1, 2, and 3, possess, and store irradiated Oconee fuel assemblies containing special nuclear material, enriched to not more than 3.24% by weight U-235 subject to the following conditions:
- a. Oconee fuel assemblies may not be placed in the McGuire Nuclear Station, Unit 1 and 2, reactors.
- b. Irradiated fuel shipped to McGuire Nuclear Station, Units 1 and 2, from Oconee shall have been removed from the Oconee reactor no less than 270 days prior to shipment.
- c. No more than 300 Oconee irradiated fuel assemblies shall be received for storage at McGuire Nuclear Station.
- d. Burnup of Oconee fuel shipped shall be no greater than 36,000 MW days per metric ton.
- e. Receipt of irradiated Oconee fuel shall be limited by the use of the NFS-4 (NAC-1), NLI-1/2, TN-8, or TN-8L spent fuel casks.
- f. The spent fuel pool crane travel shall be restricted by administrative controls to the paths required by Selected Licensee Commitment 16.9.20 whenever a spent fuel cask is being handled.
- g. Oconee fuel assemblies may not be transferred from one McGuire spent fuel pool to the other.
- 3. This renewed operating license is effective as of the date of issuance and shall expire at midnight on June 12, 2041.
FOR THE NUCLEAR REGULATORY COMMISSION J.E. Dyer, Director Office of Nuclear Reactor Regulation
Attachment:
- 1. Appendix A - Technical Specifications
- 2. Appendix B - Additional Conditions
- 3. Appendix C - Antitrust Conditions Date of Issuance: December 5, 2003 Renewed License No. NPF-9
APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. NPF-9 Duke Energy Carolinas, LLC shall comply with the following conditions on the schedules noted below:
Amendment Additional Implementation Number Conditions Date 184 The schedule for the performance of new and Within 90 days of revised surveillance requirements shall be as the date of this follows: amendment.
For surveillance requirements (SRs) that are new in Amendment No. 184 the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment No. 184. For SRs that existing prior to Amendment No. 184, including SRs with modified acceptance criteria and SRs whose intervals of performance are being extended, the first performance is due at the end of the first'surveillance interval that begins on the date the surveillance was last performed prior to implementation of amendment No. 184. For SRs that existed prior to Amendment No. 184, whose intervals of performance are being reduced, the first reduced surveillance interval begins upon completion of the first surveillance performed after implementation of Amendment No..184.
Renewed License No. NPF-9 Amendment No. 258
-B1-
APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. NPF-9 Duke Power Power Company LLC shall comply with the following conditions on the schedules noted below:
Amendment Additional Implementation Number Conditions Date 249 Upon implementation of the Amendment adopting TSTF- See Condition 448, Revision 3, the determination of control room envelope (CRE) unfiltered inleakage as required by SR 3.7.9.4, in accordance with TS 5.5.16.c.(i), the assessment of CRE habitability as required by TS 5.5.16.c.(ii), and the measurement of CRE pressure as required by TS 5.5.16.d, shall be considered met.
Following implementation:
(a) The first performance of SR 3.7.9.4 in accordance with TS 5.5.16.c.(i), shall be within the specified Frequency of 6 years, plus the 18 month allowance of SR 3.0.2, as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 letter response to Generic Letter 2003-01, or within the next 18 months if the time period since~the most recent successful tracer gas test is greater than 6 years.
(b) The first performance of the periodic assessment of CRE habitability, TS 5.5.16.c.(ii), shall be within 3 years, plus the 9 month allowance of SR 3.0.2 as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 letter response to Generic Letter 2003-01, or within the next 9 months if the time period since the most recent successful tracer gas test is greater than 3 years.
(c) The first performance of the periodic measurement of CRE pressure, TS 5.5.16.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from January 2007, the date of the most recent successful pressure measurement test, or within 138 days if not performed previously.
Renewed License No. NPF-9 Amendment No. 249 B-2
APPENDIX C ANTITRUST CONDITIONS Pursuant to an Order by the Atomic Safety and Licensing Board, dated April 23, 1975, the Nuclear Regulatory Commission incorporates in Renewed Operating License NPF-9 the following antitrust conditions:
- a. The licensee makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest. In addition, where there are net benefits to all participants such arrangements also serve the best interests of each of the participants.
Among the benefits of such transactions are increased electric system reliability, a reduction in the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.
Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating in the transaction. Accordingly, the licensee will enter into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to the licensee. There are net benefits in a transaction if the licensee recovers the cost of the transaction, (as defined in subparagraph (1)(d) hereof) and there is no demonstrable net detriment to the licensee arising from the transaction.
(1) As used herein:
(a) "Bulk Power" means electric power and any attendant energy, supplied or made available at transmission or sub-transmission voltage by one electric system to another.
(b) "Neighboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or proposing to own or operate, facilities for the generation and transmission of electricity which meets each of the following criteria:
(1) its existing or proposed facilities are economically and technically feasible of interconnection with those of the licensee and (2) with the exception of municipalities, cooperatives, governmental agencies or authorities, and associations, it is, or upon commencement of operations will be, a public utility and subject to regulation with respect to rates and service under the laws of North Carolina or South Carolina or under the Federal Power Act; provided, however, that as to associations, each member of such association is either a public utility as discussed in this clause (2) or a municipality, a cooperative or C-1
a governmental agency or authority.
(c) Where the phrase "neighboring entity" is intended to include entities engaging or proposing to engage only in the distribution of electricity, this is indicated by adding the phrase "including distribution systems."
(d) "Cost" means any appropriate operating and maintenance expenses, together with all other costs, including a reasonable return on the licensee's investment, which are reasonably allocable to a transaction.
However, no value shall be included for loss of revenue due to the loss of any wholesale or retail customer as a result of any transaction hereafter described.
(2) (a) The licensee will interconnect and coordinate reserves by means of the sale and exchange of emergency and scheduled maintenance bulk power with any neighboring entity(ies), when there are net benefits to each party, on terms that will provide for all of the licensee's properly assignable costs as may be determined by the Federal Energy Regulatory Commission and consistent with such cost assignment will allow the other party the fullest possible benefits of such coordination.
(b) Emergency service and/or scheduled maintenance service to be provided by each party will be furnished to the fullest extent available from the supplying party and desired by the party in need. The licensee and each party will provide to the other emergency service and/or scheduled maintenance service if and when available from its own generation and, in accordance with recognized industry practice, from generation of other to the extent it can do so without impairing service to its customers, including other electric systems to whom it has firm commitments.
(c) Each party to a reserve coordination arrangement will establish its own reserve criteria, but in no event shall the minimum installed reserve on each system be less than 15%, calculated as a percentage of estimated peak load responsibility. Either party, if it has, or has firmly planned, installed reserves in excess of the amount called for by its own reserve criterion, will offer any such excess as may in fact be available at the time for which it is sought and for such period as the selling party shall determine for purchase in accordance with reasonable industry practice by the other party to meet such other party's own reserve requirements. The parties will provide such amounts of spinning reserve as may be adequate to avoid the imposition of unreasonable demands on the other part(ies) in meeting the normal contingencies of operating its (their) system(s). However, in no circumstances shall such spinning reserve requirement exceed the installed reserve requirement.
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(d) Interconnections will not be limited to low voltages when higher voltages are available from the licensee's installed facilities in the area where interconnection is desired and when the proposed arrangement is found to be technically and economically feasible.
-... Interconinection and- reserve coordination agreements will-not embody
)--
provisions which impose limitations upon the use or resale of power and energy sold or exchanged pursuant to the agreement. Further, such arrangements will not prohibit the participants from entering into other interconnection and coordination arrangements, but may include appropriate provisions to assure that (i) the licensee receives adequate notice of such additional interconnection or coordination, (ii) the parties will jointly consider and agree upon such measures, if any, as are reasonably necessary to protect the reliability of the interconnected systems and to prevent undue burdens from being imposed on any system, and (iii) the licensee will be fully compensated for its costs. Reasonable industry practice as developed in the area from time to time will satisfy this provision.
(3) The licensee currently has on file, and may hereafter file, with the Federal Energy Regulatory Commission contracts with neighboring entity(ies) providing for the sale and exchange of short-term power and energy, limited term power and energy, economy energy, non-displacement energy, and emergency capacity and energy. The Licensee will enter into contracts providing for the same or for like transactions with any neighboring entity on terms which enable the licensee to recover the full costs allocable to such transaction.
(4) The licensee currently sells capacity and energy in bulk on a full requirements basis to several entities engaging in the distribution of electric power at retail. In addition, the licensee supplies electricity directly to ultimate users in a number of municipalities. Should any such entity(ies) or municipality(ies) desire to become a neighboring entity as defined in subparagraph (1)(b) hereof (either alone or through combination with others), the licensee will assist in facilitating the necessary transition through the sale of partial requirements firm power and energy to the extent that, except for such transition, the licensee would otherwise be supplying firm power and energy. The provision of such firm partial requirements service shall be under such rates, terms and conditions as shall be found by the Federal Energy Regulatory Commission to provide for the recovery of the licensee's cost. The licensee will sell. capacity and energy in bulk on a full requirements basis to any municipality currently served by the licensee when such municipality lawfully engages in the distribution of electric power at retail.
(5) (a) The licensee will facilitate the exchange of electric power in bulk in wholesale transactions over its transmission facilities (1) between or C-3
among two or more neighboring entities including distribution systems with which it is interconnected or may be interconnected in the future, and (2) between any such entity(ies) and any other electric system engaging in bulk power supply between whose facilities the licensee's transmission lines and other transmission lines would form
---a continuous electric path, provided that permissionto-utilizesuch other transmission lines has been obtained. Such transaction shall be undertaken provided that the particular transaction reasonably can be accommodated by the licensee's transmission system from a functional and technical standpoint and does not constitute the wheeling of power to a retail customer. Such transmission shall be on terms that fully compensate the licensee for its cost. Any entity(ies) requesting such transmission arrangements shall give reasonable notice of its (their) schedule and requirements.
(b) The licensee will include in its planning and construction program sufficient transmission capacity as required for the transactions referred to in subparagraph (a) of this paragraph, provided that (1) the neighboring entity(ies) gives the licensee sufficient advance notice as may be necessary reasonably to accommodate its (their) requirements from a functional and technical standpoint and (2) that such entity(ies) fully compensate the licensee for its cost. In carrying out this subparagraph (b), however, the licensee shall not be required to construct or add transmission facilities which (a) will be of no demonstrable present or future benefit to the licensee, or (b) which could be constructed by the requesting entity(ies) without duplicating any portion of the licensee's existing transmission lines, or (c) which would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements. Where regulatory or environmental approvals are required for the construction or addition of transmission facilities needed for the transactions referred to in subparagraph (a) of this paragraph it shall be the responsibility of the entity(ies) seeking the transaction to participate in obtaining such approvals, including sharing in the cost thereof.
(6) To increase the possibility of achieving greater reliability and economy of electric generation and transmission facilities, the licensee will discuss load projections and system development plans with any neighboring entity(ies).
(7) When the licensee's plans for future nuclear generating units (for which application will hereafter be made to the Nuclear Regulatory commission) have reached the stage of serious planning, but before firm decisions have been made as to the size and desired completion date of the proposed nuclear units, the licensee will notify all neighboring entities including distribution systems with peak loads smaller than the licensee's that the licensee plans to construct such C-4
nuclear units. Neither the timing nor the information provided need be such as to jeopardize obtaining the required site at the lowest possible cost.
(8) The foregoing commitments shall be implemented in a manner consistent with the provisions of the Federal Power Act and all other lawful local, state
-and Federalregulation-and authority: Nothing in these commitments-is ....
intended to determine in advance the resolution of issues which are properly raised at the Federal Energy Regulatory Commission concerning such commitments, including allocation of costs or the rates to be charged. The licensee will negotiate (including the execution of a contingent statement of intent) with respect to the foregoing commitments with any neighboring entity including distribution systems where applicable engaging in or proposing to engage in bulk power supply transactions, but the licensee shall not be required to enter into any final arrangement prior to resolution of any substantial questions as to the lawful authority of an entity to engage in the transactions.
In addition, the licensee shall not be obligated to enter into a given bulk power supply transaction if: (1) to do so would violate, or incapacitate it from performing, and existing lawful contracts it has with a third party; (2) there is contemporaneously available to it a competing or alternate arrangement which affords it greater benefits which would be mutually exclusive of such arrangement; (3) to do so would adversely affect its system operations or the reliability of power supply to its customers, or (4) if to do so would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements.
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DUKE ENERGY CAROLINAS, LLC DOCKET NO. 50-370 MCGUIRE NUCLEAR STATION, UNIT 2 RENEWED FACILITY OPERATING LICENSE Renewed License No. NPF-17
- 1. The U.S. Nuclear Regulatory Commission (Commission), having previously made the findings set forth in License No. NPF-17 issued on March 3, 1983, has now found that:
A. The application for renewed operating license filed by the Duke Energy Corporation* complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I and all required notifications to other agencies or bodies have been duly made; B. Actions have been identified and have been or will be taken with respect to (1) managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21(a)(1), and (2) time-limited aging analyses that have been identified to require review under 10 CFR 54.21 (c), such that there is reasonable assurance that the activities authorized by the renewed operating license will continue to be conducted in accordance with the current licensing basis, as defined in 10 CFR 54.3, for the McGuire Nuclear Station, Unit 2 (facility or plant), and that any changes made to the plant's current licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the Act and the Commission's regulations; C. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission; D. There is reasonable assurance: (i) that the activities authorized by this renewed operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; E. The licensee is technically qualified to engage in the activities authorized by this renewed operating license in accordance with the Commission's regulations set forth in 10 CFR Chapter I; Duke Energy Corporation converted to Duke Power Company LLC on April 3, 2006 and was re-named Duke Energy Carolinas, LLC as of October 1, 2006. Duke Energy Carolinas, LLC is the owner and operator of McGuire Nuclear Station, Unit 2. References to the "licensee" or "Duke" are to Duke Energy Carolinas, LLC.
Renewed License No. NPF-17 Amendment No. 225
F. The licensee has satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements", of the Commission's regulations; G. The issuance of this renewed operating license will not be inimical to the common defense and security or to the health and safety of the public; H. After weighing the environmental, economic, technical, and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of this Renewed Facility Operating License No. NPF-17 is in accordance with 10 CFR Part 51, of the Commission's regulations and all applicable requirements have been satisfied; and, The receipt, possession, and use of source, byproduct and special nuclear material as authorized by this renewed operating license will be in accordance with the Commissibn's regulations in 10 CFR Parts 30, 40 and 70.
- 2. Based on the foregoing findings and the Initial Decisions issued by the Atomic Safety and Licensing Board dated April 18, 1979, and May 26, 1981, and the Decision of the Atomic Safety and Licensing Appeal Board dated March 30, 1982, regarding this facility, Renewed Facility Operating License No. NPF-17 is hereby issued to Duke Energy Carolinas, LLC to read as follows:
A. This renewed operating license applies to the McGuire Nuclear Station, Unit 2, a pressurized water reactor and associated equipment (the facility) owned and operated by Duke Energy Carolinas, LLC. The facility is located on the site in Mecklenburg County, North Carolina, on the shore of Lake Norman approximately 17 miles northwest of Charlotte, North Carolina, and is described in the Updated Final Safety Analysis Report, as supplemented and amended, and in the Environmental Report, as supplemented and amended.
B. Subject to the conditions and requirements incorporated herein, the Commission hereby licenses Duke Energy Carolinas, LLC:
(1) Pursuant to Section 103 of the Act and 10 CFR Part 50, to possess, use, and operate the facility at the designated location in Mecklenburg County, North Carolina, in accordance with the procedures and limitations set forth in this renewed operating license; (2) Pursuant to the Act and 10 CFR Part 70 to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended;-
(3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70 to receive, possess and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; Renewed License No. NPF-17 Amendment No. 225
(4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as may be produced by the operation of McGuire Nuclear Station, Units 1 and 2; and, (6) Pursuant to the Act and 10 CFR Parts 30 and 40, to receive, possess and processfor release or transfer such byproduct material as may be produced by the Duke Training and Technology Center.
C. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:
(1) Maximum Power Level The licensee is authorized to operate the facility at a reactor core full steady state power level of 3411 megawatts thermal (100%).
(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 239, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.
(3) Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation.
Duke shall complete these activities no later than March 3, 2023, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.
The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following issuance of this renewed operating license.
Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59, and otherwise complies with the requirements in that section.
Renewed License No. NPF-17 Amendment No. 239
-4 (4) Fire Protection Program Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility and as approved in the SER dated March 1978 and Supplements 2, 5, and 6 dated March 1979, April 1981, and February 1983, respectively, and the safety evaluation dated May 15, 1989, subject to the following provisions:
The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.
(5) Protection of the Environment Before engaging in additional construction or operational activities which may result in a significant adverse environmental impact that was not evaluated or that is significantly greater than that evaluated in the Final Environmental Statement dated April 1976, the licensee shall provide written notification to the Office of Nuclear Reactor Regulation.
(6) Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 181, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.
(7) Antitrust Conditions The licensee shall comply with the antitrust conditions delineated in Appendix C of this renewed operating license.
(8) Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:
A) Fire fighting response strategy with the following elements:
- 1. Pre-defined coordinated fire response strategy and guidance
- 2. Assessment of mutual aid fire fighting assets
- 3. Designated staging areas for equipment and materials
- 4. Command and control
- 5. Training of response personnel B) Operations to mitigate fuel damage considering the following:
- 1. Protection and use of personnel assets
- 2. Communications
- 3. Minimizing fire spread Renewed License No. NPF-17 Amendment No. 225
- 4. Procedures for implementing integrated fire response strategy
- 5. Identification of readily-available pre-staged equipment
- 6. Training on integrated fire response strategy
- 7. Spent fuel pool mitigation measures C) Actions to minimize release to include consideration of:
- 1. Water spray scrubbing
- 2. Dose to onsite responders D. Physical Protection Duke Energy Carolinas, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on. September 30, 2004, October 15, 2004, October 21, 2004, and October 27; 2004.
E. Deleted by Amendment No. 215.
F. The licensee shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.
G. In accordance with the Commission's direction in its Statement of Policy, Licensing and Regulatory Policy and Procedures for Environmental Protection:
Uranium Fuel Cycle Impacts, October 29, 1982, this renewed operating license is subject to the final resolution of the pending litigation involving Table S-3.
See, Natural Resources Defense Council v. NRC, No..74-1586 (D.C. cir. April 27, 1982).
H. The licensee is authorized to receive from the Oconee Nuclear Station, Units 1, 2, and 3, possess, and store irradiated Oconee fuel assemblies containing special nuclear material, enriched to not more than 3.24% by weight U-235 subject to the following conditions:
- a. Oconee fuel assemblies may not be placed in the McGuire Nuclear Station, Unit 1 and 2, reactors.
- b. Irradiated fuel shipped to McGuire Nuclear Station, Units 1 and 2, from Oconee shall have been removed from the Oconee reactor no less than 270 days prior to shipment.
Renewed License No. NPF-17 Amendment No. 225
- c. No more th-an 300 Oconee irradiated fuel assemblies shall be received for storage at McGuire Nuclear Station.
- d. Burnup of Oconee fuel shipped shall be no greater than 36,000 MW days per metric ton.
- e. Receipt of irradiated Oconee fuel shall be limited by the use of the NFS-4 (NAC-1), NLI-1/2, TN-8, or TN-8L spent fuel casks.
- f. The spent fuel pool crane travel shall be restricted by administrative controls to the paths required by Selected Licensee Commitment 16.9.20 whenever a spent fuel cask is being handled.
- g. Oconee fuel assemblies may not be transferred from one McGuire spent fuel pool to the other.
- 3. This renewed operating license is effective as of the date of issuance and shall expire at midnight on March 3, 2043.
FOR THE NUCLEAR REGULATORY COMMISSION J.E. Dyer, Director Office of Nuclear Reactor Regulation
Attachment:
- 1. Appendix A - Technical Specifications
- 2. Appendix B - Additional Conditions
- 3. Appendix C - Antitrust Conditions Date of Issuance: December 5, 2003 Renewed License No. NPF-17
APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. NPF-17 Duke Energy Carolinas, LLC shall comply with the following conditions on the schedules noted below:
Amendment Additional Implementation Number Conditions Date 166 The schedule for the performance of new and Within 90 days of revised surveillance requirements shall be as the date of this follows: amendment.
For surveillance requirements (SRs) that are new in Amendment No. 166 the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment No. 166. For SRs that existed prior to Amendment No. 166, including SRs with modified acceptance criteria and SRs whose intervals of performance are being extended, the first performance is due at the end of the first surveillance interval that begins on the date the surveillance was last performed prior to implementation of amendment No. 166. For SRs that existed prior to Amendment No. 166, whose intervals of performance are being reduced, the first reduced surveillance interval begins upon completion of the first surveillance performed after implementation of Amendment No. 166.
I Renewed License No. NPF-17 Amendment No. 238 B-1
APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. NPF-17 Duke Power Power Company LLC shall comply with the following conditions on the schedules noted below:
Amendment Additional Implementation Number Conditions Date 229 Upon implementation of the Amendment adopting See Condition TSTF-448, Revision 3, the determination of control room envelope (CRE) unfiltered inleakage as required by SR 3.7.9.4, in accordance with TS 5.5.16.c.(i), the assessment of CRE habitability as required by TS 5.5.16.c.(ii), and the measurement of CRE pressure as required by TS 5.5.16.d, shall be considered met.
Following implementation:
(a) The first performance of SR 3.7.9.4 in accordance with TS 5.5.16.c.(i), shall be within the specified Frequency of 6 years, plus the 18 month allowance of SR 3.0.2, as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 letter response to Generic Letter 2003-01, or within the next 18 months if the time period since the most recent successful tracer gas test is greater than 6 years.
(b) The first performance of the periodic assessment of CRE habitability, TS 5.5.16.c.(ii), shall be within 3 years, plus the 9 month allowance of SR 3.0.2 as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the-February 19, 2004 letter response to Generic Letter 2003-01, or within the next 9 months if the time period since the most recent successful tracer gas test is greater than 3 years.
(c) The first performance of the periodic measurement of CRE pressure, TS 5.5.16.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from January 2007, the date of the most recent successful pressure measurement test, or within 138 days if not performed previously.
Renewed License No. NPF-17 Amendment No. 229 B-2
APPENDIX C ANTITRUST CONDITIONS Pursuant to an Order by the Atomic Safety and Licensing Board, dated April 23, 1975, the Nuclear Regulatory Commission incorporates in Operating License NPF-17 the following antitrust conditions:
- a. The licensee makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest. In addition, where there are net benefits to all participants such arrangements also serve the best interests of each of the participants.
Among the benefits of such transactions are increased electric system reliability, a reduction in the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.
Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating in the transaction. Accordingly, the licensee will enter into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to the licensee. There are net benefits in a transaction if the licensee recovers the cost of the transaction (as defined in subparagraph (1)(d) hereof) and there is no demonstrable net detriment to'the licensee arising from the transaction.
(1) As used herein:
(a) "Bulk Power" means electric power and any attendant energy, supplied or made available at transmission or sub-transmission voltage by one electric system to another.
(b) "Neighboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or proposing to own or operate, facilities for the generation and transmission of electricity which meets each of the following criteria:
(1) its existing or proposed facilities are economically and technically feasible of interconnection with those of the licensee and (2) with the exception of municipalities, cooperatives, governmental agencies or authorities, and associations, it is, or upon commencement of operations will be, a public utility and subject to regulation with respect to rates and service under the laws of North Carolina or South Carolina or under the Federal Power Act; provided, however, that as to associations, each member of such association is either a public utility as discussed in this clause (2) or C-1
a municipality, a cooperative or a governmental agency or authority.
(c) Where the phrase "neighboring entity" is intended to include entities engaging or proposing to engage only in the distribution of electricity, this is indicated by adding the phrase "including distribution systems."
(d) "Cost means any appropriate operating and maintenance expenses, together with all other costs, including a reasonable return on the licensee's investment, which are reasonably allocable to a transaction.
However, no value shall be included for loss of revenue due to the loss of any wholesale or retail customer as a result of any transaction hereafter described.
- (2) (a) The licensee will interconnect and coordinate reserves by means of the sale and exchange of emergency and scheduled maintenance bulk power with any neighboring entity(ies), when there are net benefits to each party, on terms that will provide for all of the licensee's properly assignable costs as may be determined by the Federal Energy Regulatory Commission and consistent with such cost assignment will allow the other party the fullest possible benefits of such coordination.
(b) Emergency service and/or scheduled maintenance service to be provided by each party will be furnished to the fullest extent available from the supplying party and desired by the party in need. The licensee and each party will provide to the other emergency service and/or scheduled maintenance service if and when available from its own generation and, in accordance with recognized industry practice, from generation of other to the extent it can do so without impairing service to its customers, including other electric systems to whom it has firm commitments.
(c) Each party to a reserve coordination arrangement will establish its own reserve criteria, but in no event shall the minimum installed reserve on each system be less than 15%, calculated as a percentage of estimated peak load responsibility. Either party, if it has, or has firmly planned, installed reserves in excess of the amount called for by its own reserve criterion, will offer any such excess as may in fact be available at the time for which it is sought and for such period as the selling party shall determine for purchase in accordance with reasonable industry practice by the other party to meet such other party's own reserve requirements. The parties will provide such amounts of spinning reserve as may be adequate to avoid the imposition of unreasonable demands on the other part(ies) in meeting the normal contingencies of operating its (their) system(s). However, in no circumstances shall such spinning reserve requirement exceed the installed reserve requirement.
(d) Interconnections will not be limited to low voltages when higher voltages are C-2
available from the licensee's installed facilities in the area where interconnection is desired and when the proposed arrangement is found to be technically and economically feasible.
(e) Interconnection and reserve coordination agreements will not embody provisions which impose limitations upon the use or resale of power and energy sold or exchanged pursuant to the agreement. Further, such arrangements will not prohibit the participants from entering into other interconnection and coordination arrangements, but may include appropriate provisions to assure that (i) the licensee receives adequate notice of such additional interconnection or coordination, (ii) the parties will jointly consider and agree upon such measures, if any, as are reasonably necessary to protect the reliability of the interconnected systems and to prevent undue burdens from being imposed on any system, and (iii) the licensee will be fully compensated for its costs. Reasonable industry practice as developed in the area from time to time will satisfy this provision.
(3) The licensee currently has on file, and may hereafter file, with the Federal Energy Regulatory Commission contracts with neighboring entity(ies) providing for the sale and exchange of short-term power and energy, limited term power and energy, economy energy, non- displacement energy, and emergency capacity and energy. The Licensee will enter into contracts providing for the same or for like transactions with any neighboring entity on terms which enable the licensee to recover the full costs allocable to such transaction.
'(4) The licensee currently sells capacity and energy in bulk on a full requirements basis to several entities engaging in the distribution of electric power at retail. In addition, the licensee supplies electricity directly to ultimate users in a number of municipalities. Should any such entity(ies) or municipality(ies) desire to become a neighboring entity as defined in subparagraph (1)(b) hereof (either alone or through combination with others), the licensee will assist in facilitating the necessary transition through the sale of partial requirements firm power and energy to the extent that, except for such transition, the licensee would otherwise be supplying firm power and energy. The provision of such firm partial requirements service shall be under such rates, terms and conditions as shall be found by the Federal Energy Regulatory Commission to provide for the recovery of the licensee's cost. The licensee will sell capacity and energy in bulk on a full requirements basis to any municipality currently served by the licensee when such municipality lawfully engages in the distribution of electric power at retail.
(5) (a) The licensee will facilitate the exchange of electric power in bulk in wholesale transactions over its transmission facilities (1) between or among two or more neighboring entities including distribution systems with which it is interconnected or may be interconnected in the future, and (2) between any such entity(ies) and any other electric system engaging in bulk power supply between whose facilities the licensee's transmission C-3
lines and other transmission lines would form a continuous electric path, provided that permission to utilize such other transmission lines has been obtained. Such transaction shall be undertaken provided that the particular transaction reasonably can be accommodated by the licensee's transmission system from a functional and technical standpoint and does not constitute the wheeling of power to a retail customer. Such transmission shall be on terms that fully compensate the licensee for its cost. Any entity(ies) requesting such transmission arrangements shall give reasonable notice of its (their) schedule and requirements.
(b) The licensee will include in its planning and construction program sufficient transmission capacity as required for the transactions referred to in subparagraph (a) of this paragraph, provided that (1) tihe neighboring entity(ies) gives the licensee sufficient advance notice as may be necessary reasonably to accommodate its (their) requirements from a functional and technical standpoint and (2) that such entity(ies) fully compensate the licensee for its cost. In carrying out this subparagraph (b), however, the licensee shall not be required to construct or add transmission facilities which (a) will be of no demonstrable present or future benefit to the licensee, or (b) which could be constructed by the requesting entity(ies) without duplicating any portion of the licensee's existing transmission lines, or (c) which would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements. Where regulatory or environmental approvals are required for the construction or addition of transmission facilities needed for the transactions referred to in subparagraph (a) of this paragraph it shall be the responsibility of the entity(ies) seeking the transaction to participate in obtaining such approvals, including sharing in the cost thereof.
(6) To increase the possibility of achieving greater reliability and economy of electric generation and transmission facilities, the licensee will discuss load projections and system development plans with any neighboring entity(ies).
(7) When the licensee's plans for future nuclear generating units (for which application will hereafter be made to the Nuclear Regulatory commission) have reached the stage of serious planning, but before firm decisions have been made as to the size and desired completion date of the proposed nuclear units, the licensee will notify all neighboring entities including distribution systems with peak loads smaller than the licensee's that the licensee plans to construct such nuclear units. Neither the timing nor the information provided need be such as to jeopardize obtaining the required site at the lowest possible cost.
The foregoing commitments shall be implemented in a manner consistent with the provisions of the Federal Power Act and all other lawful local, state and Federal regulation and authority. Nothing in these commitments is intended to determine in advahce the resolution of issues which are properly raised at the Federal Energy Regulatory Commission concerning such commitments, C-4
including allocation of costs or the rates to be charged. The licensee will negotiate (including the execution of a contingent statement of intent) with respect to the foregoing commitments with any neighboring entity including distribution systems where applicable engaging in or proposing to engage in bulk power supply transactions, but the licensee shall not be required to enter into any final arrangement prior to resolution of any substantial questions as to the lawful authority of an entity to engage in the transactions.
In addition, the licensee shall not be obligated to enter into a given bulk power supply transaction if: (1) to do so would violate, or incapacitate it from performing, and existing lawful contracts it has with a third party; (2) there is contemporaneously available to it a competing or alternate arrangement which affords it greater benefits which would be mutually exclusive of such arrangement; (3) to do so would adversely affect its system operations or the reliability of power supply to its customers, or (4) if to do so would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements.
C-5
McGuire Nuclear Station Technical Specifications LOEP Page Number Amendment Revision Date 184/166 9/30/98 623/2_9
. 3/1/07/
iii 184/166 9/30/98 iv 184/166 9/30/98 1.1-1 184/166 9/30/98 1.1-2 184/166 9/30/98 1.1-3 237/219 3/1/07 1.1-4 194/175 9/18/00 1.1-5 255/235 5/28/10 1.1-6 206/187 8/23/02 1.1-7 194/175 9/18/00 1.2-1 184/166 9/30/98 1.2-2 184/166 9/30/98 1.2-3 184/166 9/30/98 1.3-1 184/166 9/30/98 1.3-2 184/166 9/30/98 1.3-3 184/166 9/30/98 1.3-4 184/166 9/30/98 1.3-5 184/166 9/30/98 1.3-6 184/166 9/30/98 1.3-7 184/166 9/30/98 1.3-8 184/166 9/30/98 1.3-9 184/166 °9/30/98 1.3-10 184/166 9/30/98 1.3-11 184/166 9/30/98 1.3-12 184/166 9/30/98 1.3-13 184/166 9/30/98 1.4-1 184/166 9/30/98 1.4-2 184/166 9/30/98 1.4-3 184/166 9/30/98 1.4-4 184/166 9/30/98 2.0-1 219/201 1/14/04 McGuire Units 1 and 2 Page I Revision 89
Page Number Amendment Revision Date 3.0-1 238/220 3/29/07 3.0-2 221/203 4/29/04 3.0-3 238/220 3/29/07 3.0-4 205/186 8/12/02 3.0-5 221/203 4/29/04 3.1.1-1 184/166 9/30/98 3.1.2-1 184/166 9/30/98 3.1.2-2 184/166 9/30/98 3.1.3-1 184/166 9/30/98 3.1.3-2 184/166 9/30/98 3.1.3-3 184/166 9/30/98 3.1.4-1 184/166 9/30/98 3.1.4-2 184/166 9/30/98 3.1.4-3 184/166 9/30/98 3.1.4-4 186/167 9/8/99 3.1.5-1 184/166 9/30/98 3.1.5-2 184/166 9/30/98 3.1.6-1 184/166 9/30/98 3.1.6-2 184/166 9/30/98 3.1.6-3 184/166 9/30/98 3.1.7-1 184/166 9/30/98 3.1.7-2 184/166 9/30/98 3.1.8-1 184/166 9/30/98 3.1.8-2 184/166 9/30/98 3.2.1-1 184/166 9/30/98 3.2.1-2 184/166 9/30/98 3.2.1-3 184/166 9/30/98 3.2.1-4 188/169 9/22/99 3.2.1-5 188/169 9/22/99 3.2.2-1 184/166 9/30/98 3.2.2-2 184/166 9/30/98 3.2.2-3 184/166 9/30/98 3.2.2-4 188/169 9/22/99 3.2.3-1 184/166 9/30/98 McGuire Units 1 and 2 Page 2 Revision 89
Page Number Amendment Revision Date 3.2.4-1 184/166 9/30/98 3.2.4-2 184/166 9/30/98 3.2.4-3 184/166 9/30/98 312.4-4 184/166 9/30/98 3.3.1-1 184/166 9/30/98 3,3.1-2 248/228 3/9/09 3,3.1-3 248/228 3/9/09 3,3.1-4 216/197 7/29/03 3,3.1-5 250/230 3/9/09 3.3.1-6 248/228 3/9/09 3.3.1-7 248/228 3/9/09 3.3.1-8 184/166 9/30/98 3.3.1-9 184/166 9/30/98 3,3.1-10 248/228 3/9/09 3.3.1-11 248/228 3/9/09 3.3.1-12 257/237 8/2/10 3,3.1-13 184/166 9/30/98 3,3.1-14 257/237 8/2/10 3.3.1-15 257/237 8/2/10 3,3.1-16 257/237 8/2/10 3.3.1-17 257/237 8/2/10 3.3.1-18 219/201 1/ 14/04 3,3.1-19 219/201 1/14/04 3,3.1-20 184/166 9/30/98 3,3.2-1 184/166 9/30/98 3,3.2-2 250/230 3/9/09 3,3.2-3 248/228 3/9/09 3,3.2-4 248/228 3/9/09 3,3.2-5 248/228 3/9/09 3,3.2-6 198/179 4/12/01 3,3.2-7 198/179 4/12/01 3.3.2-8 250/230 3/9/09 3.3.2-9 184/166 9/30/98 McGuire Units 1 and 2 Page 3 Revision 89
Page Number Amendment Revision Date 3.3.2-10 220/202 3/18/04 3.3.2-11 220/202 3/18/04 3.3.2-12 224/206 1/27/05 3.3.2-13 220/202 3/18/04 3.3.2-14 220/202 3/18/04 3.3.3-1 221/203 4/29/04 3.3.3-2 227/209 4/4/05 3.3.3-3 227/209 4/4/05 3.3.3-4 227/209 4/4/05 3.3.4-1 221/203 4/29/04 3.3.4-2 184/166 9/30/98 3.3.4-3 184/166 9/30/98 3.3.5-1 184/166 9/30/98 3.3.5-2 194/175 9/18/00 3.3.6-1 Not Used - 243/224 7/26/07 3.4.1-1 219/201 1/14/04 3.4.1-2 219/201 1/14/04 3.4.1-3 184/166 9/30/98 3.4.1-4 219/201 1/14/04 3.4.2-1 184/166 9/30/98 3.4.3-1 214/195 7/3/03 3.4.3-2 184/166 9/30/98 3.4.3-3 214/195 7/3/03 3.4.3-4 214/195 7/3/03 3.4.3-5 214/195 7/3/03 3.4.3-6 214/195 7/3/03 3.4.3-7 214/195 7/3/03 3.4.3-8 214/195 7/3/03 3.4.4-1 184/166 9/30/98 3.4.5-1 216/197 7/29/03 3.4.5-2 216/197 7/29/03 3.4.5-3 184/166 9/30/98 3.4.6-1 216/197 7/29/03 3.4.6-2 216/197 7/29/03 McGuire Units 1 and 2 Page 4 Revision 89
Page Number Amendment Revision Date 3.4.7-1 216/197 7/29/03 3.4.7-2 216/197 7/29/03 3.4.7-3 216/197 7/29/03 3.4.8-1 216/197 7/29/03 3.4.8-2 216/197 7/29/03 3.4.9-1 184/166 9/30/98 3.4.9-2 184/166 9/30/98 3.4.10-1 184/166 9/30/98 3.4.10-2 184/166 9/30/98 3.4-11-1 221/203 4/29/04 3.4.11-2 184/166 9/30/98 3.4-11-3 184/166 9/30/98 3.4.11-4 184/166 9/30/98 3.4.12-1 184/166 9/30/98 3.4.12-2 221/203 4/29/04 3.4.12-3 214/195 7/3/03 3.4.12-4 214/195 7/3/03 3.4.12-5 184/166 9/30/98 3.4.12-6 184/166 9/30/98 3.4.13-1 237/219 3/1/07 3.4.13-2 237/219 3/1/07 3.4.14-1 184/166 9/30/98 3.4.14-2 184/166 9/30/98 3.4.14-3 184/166 9/30/98 3.4.14-4 184/166 9/30/98 3.4.15-1 235/217 9/30/06 3.4.15-2 235/217 9/30/06 3.4.15-3 235/217 9/30/06 3.4.15-4 235/217 9/30/06 3.4.16-1 221/203 4/29/04
.3.4.16-2 184/166 9/30/98 3.4.16-3 184/166 9/30/98 3.4.16-4 !184/166 9/30/98 McGuire Units I and 2 Page 5 Revision 89
Page Number Amendment Revision Date 3.4.17-1 184/166 9/30/98 3.4.18-1 237/219 3/1/07 3.4.18-2 237/219 3/1/07 3.5.1-1 218/200 12/23/03 3.5.1-2 184/166 9/30/98 3.5.2-1 184/166 9/30/98 3.5.2-2 184/166 9/30/98 3.5.2-3 240/222 5/4/07 3.5.3-1 221/203 4/29/04 3.5.3-2 184/166 9/30/98 3.5.4-1 184/166 9/30/98 3.5.4-2 184/166 9/30/98 3.5.5-1 184/166 9/30/98 3.5.5-2 184/166 9/30/98 3.6.1-1 207/188 9/4/02 3.6.1-2 207/188 9/4/02 3.6.2-1 184/166 9/30/98 3.6.2-2 184/166 9/30/98 3.6.2-3 184/166 9/30/98 3.6.2-4 184/166, 9/30/98 3.6.2-5 207/188 9/4/02 3.6.3-1 243/224 7/26/07 3.6.3-2 184/166 9/30/98 3.6.3-3 184/166 9/30/98 3.6.3-4 184/166 9/30/98 3.6.3-5 243/224 7/26/07 3.6.3-6 243/224 7/26/07 3.6.3-7 207/188 9/4/02 3.6.4-1 184/166 9/30/98 3.6.5-1 184/166 9/30/98 3.6.5-2 184/166 9/30/98 3.6.6-1 184/166 9/30/98 3.6.6-2 259/239 8/24/2010 3.6.7-1 Not Used - 227/209 4/4/05 McGuire Units 1 and 2 Page 6 Revision 89
Page Number Amendment Revision Date 3.6.8-1 221/203 4/29/04 3.6.8-2 184/166 9/30/98 3.6.9-1 184/166 9/30/98 3.6.9-2 184/166 9/30/98 3.6.10-1 184/166 9/30/98 3.6.10-2 184/166 9/30/98 3.6.11-1 184/166 9/30/98 3.6.11-2 184/166 9/30/98 3.6.12-1 184/166 9/30/98 3.6.12-2 217/199 9/29/03 3.6.12-3 217/199 9/29/03 3.6.13-1 256/236 6/28/10 3.6.13-2 256/236 6/28/10 3.6.13-3 256/236 6/28/10 3.6.14-1 228/210 4/5/05 3.6.14-2 184/166 9/30/98 3.6.14-3 184/166 9/30/98 3.6.15-1 184/166 9/30/98 3.6.15-2 184/166 9/30/98 3.6.16-1 212/193 5/8/03 3.6.16-2 212/193 5/8/03 3.7.1-1 184/166 9/30/98 3.7.1-2 184/166 9/30/98 3.7.1-3 184/166 9/30/98 3.7.2-1 184/166 9/30/98 3.7.2-2 184/166 9/30/98 3.7.3-1 184/166 9/30/98 3.7.3-2 184/166 9/30/98 3.7.4-1 221/203 4/29/04 3.7.4-2 184/166 9/30/98 3.7.5-1 221/203 4/29/04 3.7.5-2 184/166 9/30/98 3.7.5-3 184/166 9/30/98 3.7.5-4 184/166 9/30/98 McGuire Units 1 and 2 Page 7 Revision 89
Page Number Amendment Revision Date 3.7.6-1 184/166 9/30/98 3.7.6-2 184/166 9/30/98 3.7.7-1 184/166 9/30/98 3.7.7-2 184/166 9/30/98 3.7.8-1 184/166 9/30/98 3.7.8-2 184/166 9/30/98 3.7.9-1 249/229 1/30/09 3.7.9-2 249/229 1/30/09 3.7.9-3 249/229 1/30/09 3.7.10-1 184/166 9/30/98 3.7.10-2 184/166 9/30/98 3.7.11-1 229/211 6/2/05 3.7.11-2 184/166 9/30/98 3.7.12-1 184/166 9/30/98 3.7.12-2 184/166 9/30/98 3.7.13-1 184/166 9/30/98 3.7.14-1 184/166 9/30/98 3.7.15-1 225/207 3/17/05 3.7.15-2 225/207 3/17/05 3.7.15-3 225/207 3/17/05 3.7.15-4 225/207 3/17/05 3.7.15-5 225/207 3/17/05 3.7.15-6 225/207 3/17/05 3.7.15-7 225/207 3/17/05 3.7.15-8 225/207 3/17/05 3.7.15-9 225/207 3/17/05 3.7.15-10 225/207 3/17/05 3.7.15-11 225/207 3/17/05 3.7.15-12 225/207 3/17/05 3.7.15-13 225/207 3/17/05 3.7.15-14 225/207 3/17/05 3.7.15-15 225/207 3/17/05 3.7.15-16 225/207 3/17/05 3.7.15-17 225/207 3/17/05 Page 8 McGuire Units 1 and 2 Revision 89
Page Number Amendment Revision Date 3.7.15-18 225/207 3/17/05 3.7.15-19 225/207 3/17/05 3.7.15-20 225/207 3/17/05 3.7.15-21 225/207 3/17/05 3.7.15-22 225/207 3/17/05 3.7.15-23 225/207 3/17/05 3.7.15-24 225/207 3/17/05 3.7.15-25 225/207 3/17/05 3.7.15-26 225/207 3/17/05 3.7.15-27 225/207 3/17/05 3.7.15-28 225/207 3/17/05 3.7.15-29 225/207 3/17/05 3.7.15-30 225/207 3/17/05 3.7.15-31 225/207 3/17/05 3.7.15-32 225/207 3/17/05 3.7.16-1 184/166 9/30/98 3.8.1-1 221/203 4/29/04 3.8.1-2 184/166 9/30/98 3.8.1-3 241/-, 06/08/07 3.8.1-4 184/166 9/30/98 3.8.1-5 184/166 9/30/98 3.8.1-6 254/234 05/05/10 3.8.1-7 184/166 9/30/98 3.8.1-8 192/173 3/15/00 3.8.1-9 184/166 9/30/98 3.8.1-10 184/166 9/30/98 3.8.1-11 242/223 7/25/07 3.8.1-12 184/166 9/30/98 3.8.1-13 184/166 9/30/98 3.8.1-14 184/166 9/30/98 3.8.1-15 184/166 9/30/98 3.8.2-1 184/166 9/30/98 3.8.2-2 216/197 7/29/03.
3.8.2-3 184/166 9/30/98 McGuire Units 1 and 2 Page 9 Revision 89
Page Number Amendment Revision Date 3.8.3-1 184/166 9/30/98 3.8.3-2 184/166 9/30/98 3.8.3-3 215/196 8/4/03 3.8.4-1 184/166 9/30/98 3.8.4-2.................
3.8.4-2 184/166 9/30/98 3.8.4-3 209/190 12/17/02 3.8.5-1 184/166 9/30/98 3.8.5-2 216/197 7/29/03 3.8.6-1 184/166 9/30/98 3.8.6-2 184/166 9/30/98 3.8.6-3 184/166 9/30/98 3.8.6-4 184/166 9/30/98 3.8.7-1 184/166 9/30/98 3.8.8-1 184/166 9/30/98 3.8.8-2 216/197 7/29/03 3.8.9-1 184/166 9/30/98 3.8.9-2 184/166 9/30/98 3.8.10-1 216/197 7/29/03 3.8.10-2 184/166 9/30/98 3.9.1-1 231/213 9/1/05 3.9.2-1 184/166 9/30/98 3.9.3-1 216/197 7/29/03 3.9.3-2 184/166 9/30/98 3.9.4-1 236/218 12/22/06 3.9.4-2 184/166 9/30/98 3.9.5-1 216/197 7/29/03 3.9.5-2 184/166 9/30/98 3.9.6-1 216/197 7/29/03 3.9.6-2 184/166 9/30/98 3.9.7-1 184/166 9/30/98 4.0.1 225/207 3/17/05 4.0.2 225/207 3/17/05 5.1-1 213/194 6/6/03 5.2-1 239/221 04/12/07 McGuire Units 1 and 2 Page 10 Revision 89
Page Number Amendment Revision Date 5.2-2 253/233 9/21/09 5.3-1 213/194 6/6/03 5.4-1 184/166 9/30/98 5.5-1 244/193 2/13/08 5.5-2 212/193 5/8/03 5.5-3 184/166 9/30/98 5.5-4 184/166 9/30/98 5.5-5 223/205 8/5/04 5.5-6 252/232 8/17/09 5.5-7 237/219 3/1/07 5.5-8 237/219 3/1/07 5.5-9 237/219 3il/07 5.5-10 237/219 3/1/07 5.5-11 237/219 3/1/07 5.5-12 237/219 3/1/07 5.5-13 237/219 3/1/07 5.5-14 249/229 1/30/09 5.5-15 249/229 1/30/09 5.6-1 226/208 3/1/07 5.6-2 226/208 3/1/07 5.6-3 226/208 3/1/07 5.6-4 230/212 8/23/05 5.6-5 237/219 3/1/07 5.7-1 213/194 6/6/03 5.7-2 184/166 9/30/98 I
McGuire Units 1 and 2 Page 11l Revision 89
Containment Spray System
"- 3.6.6 SURVEILLANCE FREQUENCY
---SR -3.6;6-2 -Verify each containment spray pump's developed-head at In accordance with the flow test point is greater than or equal to the required the Inservice developed head. Testing Program
- SR 3.6.6.3 Verify each automatic containment spray valve in the flow 18 months path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.
SR 3.6.6.4 Verify each containment spray pump starts automatically 18 months on an actual or simulated actuation signal.
SR 3.6.6.5 Verify that each spray pump is de-energized and 18 months prevented from starting upon receipt of a terminate signal and is allowed to start upon receipt of a start permissive from the Containment Pressure Control System (CPCS).
SR 3.6.6.6 Verify that each spray pump discharge valve closes or is 18 months prevented from opening upon receipt of a terminate signal and is allowed to open upon receipt of a start permissive from the Containment Pressure Control System (CPCS).
SR 3.6.6.7 Verify each spray nozzle is unobstructed. Following activities which could result in nozzle blockage McGuire Units I and 2 3.6.6-2 Amendment Nos. 259/239
McGuire Nuclear Station Technical Specification Bases LOES TS Bases are revised by section Page Number Revision Revision Date BASES
( Revision 87 8/15/07 ii Revision 87 8/15/07 iii Revision 87 8/15/07 B 2.1.1 Revision 51 01/14/04 B 2.1.2 Revision 109 9/20/10 B 3.0 Revision*81 3/29/07 B 3.1.1 Revision 73 3/6/06 B 3.1.2 Revision 10 9/22/00 B 3.1.3 Revision 10 9/22/00 B 3.1.4 Revision 0 9/30/98 B 3.1.5 Revision 19 1/10/02 B 3.1.6 Revision 0 9/30/98 B 3.1.7 Revision 58 06/23/04 B 3.1.8 Revision 0 9/30/98 B 3.2.1 Revision 74 5/3/06 B 3.2.2 Revision 10 9/22/00 B 3.2.3 Revision 34 10/1/02 B 3.2.4 Revision 10 9/22/00 B 3.3.1 Revision 108 8/2/10 B 3.3.2 Revision 99 3/9/09 B 3.3.3 Revision 100 4/13/09 B 3.3.4 Revision 57 4/29/04 B 3.3.5 Revision 11 . 9/18/00 B 3.3.6 Not Used - Revision 87 6/29/06 B 3.4.1 Revision 51 1/14/04 B 3.4.2 Revision 0 9/30/98 B 3.4.3 Revision 44 7/3/03 B 3.4.4 Revision 86 6/25/07 B 3.4.5 Revision 86 6/25/07 McGuire Units 1 and 2 Page I Revision 103
Page Number Amendment Revision Date B 3.4.6 Revision 86 6/25/07 B 3.4.7 Revision 86 6/25/07 B 3.4.8 Revision 41 7/29/03 B 3.4.9 Revision 0 9/30/98
.B 3.4.10 Revision 102 8/17/09 B 3.4.11 Revision 102 8/17/09 B 3.4.12 Revision 102 8/17/09 B 3.4.13 Revision 86 6/25/07 B 3.4.14 Revision 102 8/17/09 B 3.4.15 Revision 82 9/30/06 B 3.4.16 Revision 57 4/29/04 J
B 3.4.17 Revision 0 9/30/98 B 3.4.18 Revision 86 6/25/07 B 3.5.1 Revision 70 10/5/05 B 3.5.2 Revision 102 8/17/09 B 3.5.3 Revision 57 4/29/04 B 3.5.4 Revision 70 10/5/04 B 3.5.5 Revision 0 9/30/98 B 3.6.1 Revision 53 2/17/04 B 3.6.2 Revision 98 3/24/09 B 3.6.3 Revision 87 6/29/06 B 3.6.4 Revision 0 9/30/98 B 3.6.5 Revision 0 9/30/98 B 3.6.5-2 Revision 6 10/6/99 B 3.6.6 Revision 110 9/22/10 B 3.6.7 Not Used - Revision 63 4/4/05 B 3.6.8 Revision 63 4/4/05 B 3.6.9 Revision 63 4/4/05 B 3.6.10 Revision 109 9/20/10 B 3.6.11 Revision 78 9/25/06 B 3.6.12 Revision 53 2/17/04 B 3.6.13 Revision 104 6/28/10 B 3.6.14 Revision 64 4/23/05 B 3.6.15 Revision 0 9/30/98 McGuire Units 1 and 2 Page 2 Revision 103
Page Number Amendment Revision Date B 3.6.16 Revision 40 5/8/03 B 3.7.1 Revision 102 8/17/09 B 3.7.2 Revision 105 2/22/10 B 3.7.3 Revision 102 8/17/09 B 3.7.4 Revision 57 4/29/04 B 3.7.5 Revision102 8/17/09 B 3.7.6 Revision 0 9/30/98 B 3.7.7 Revision 101 9/17/09 B 3.7.8 Revision 107 6/23/10 B 3.7.9 Revision 109 9/20/10 B 3.7.10 Revision 75 6/12/06 B 3.7.11 Revision 109 9/20/10 B 3.7.12 Revision 28 5/17/02 B 3.7.13 Revision 85 2/26/07 B 3.7.14 Revision 66 6/30/05 B 3.7.15 Revision 66 6/30/05 B 3.7.16 Revision 0 9/30/98 B 3.8.1 Revision 111 9/23/10 B 3.8.2 Revision 92 1/28/08 B 3.8.3 Revision 103 12/15/08 B 3.8.4 Revision 100 4/13/09 B 3.8.5 Revision 41 7/29/03 B 3.8.6 Revision 0 9/30/98 B 3.8.7 Revision 20 1/10/02 B 3.8.8 Revision 41 7/29/03 B 3.8.9 Revision 24 2/4/02 B 3.8.10 Revision 41 7/29/03 B 3.9.1 Revision 68 9/1/05 B 3.9.2 Revision 41 7/29/03 B 3.9.3 Revision 108 8/2/10 B 3.9.4 Revision 84 2/20/07 B 3.9.5 Revision 59 7/29/04 B 3.9.6 Revision 41 7/29/03 B 3.9.7 Revision 88 9/5/07 McGuire Units 1 and 2 Page 3 Revision 103
RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs)
B 2.1.2 Reactor Coolant System (RCS) Pressure SL BACKGROUND The SL on RCS pressure protects the integrity of the RCS against overpressurization. In the event of fuel cladding failure, fission products are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere. By establishing an upper limit on RCS pressure, the continued integrity of the RCS is ensured. According to 10 CFR 50, Appendix A, GDC 14, "Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) design conditions are not to be exceeded during normal operation and anticipated operational occurrences (AOOs).
Also, in accordance with GDC 28, "Reactivity Limits" (Ref. 1), reactivity accidents, including rod ejection, do not result in damage to the RCPB greater than limited local yielding.
The design pressure of the RCS is 2500 psia. During normal operation and AOOs, RCS pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code (Ref. 2). To ensure system integrity, all RCS components are hydrostatically tested at 125% of design pressure, according to the ASME Code requirements prior to initial operation when there is no fuel in the core. Following inception of unit operation, RCS components shall be pressure tested, in accordance with the requirements of the ASME OM Code (Ref. 3). /
Overpressurization of the RCS could result in a breach of the RCPB. If such a breach occurs in conjunction with a fuel cladding failure, fission products could enter the containment atmosphere, raising concerns relative to limits on radioactive releases specified in 10 CFR 50.67, "Accident Source Term" (Ref. 4).
APPLICABLE The RCS pressurizer safety valves, the main steam safety valves SAFETY ANALYSES (MSSVs), and the reactor high pressure trip have settings established to ensure that the RCS pressure SL will not be exceeded.
The RCS pressurizer safety valves are sized to prevent system piressure from exceeding the design pressure by more than 10%, as specified in Section III of the ASME Code for Nuclear Power Plant Components McGuire Units 1 and 2 B 2.1.2-1 Revision No. 109
RCS Pressure SL B 2.1.2 BASES APPLICABLE SAFETY ANALYSES (continued)
(Ref.-2), *fr anticipated op e
--- nrtal occurrences. During the transient. no control actions are assumed, except that the safety valves on the secondary plant are assumed to open when the steam pressure reaches the secondary plant safety valve settings, and nominal feedwater supply is maintained.
The Reactor Trip System setpoints (Ref. 5), together with the settings of the MSSVs, provide pressure protection for normal operation and AOOs.
The reactor high pressure trip setpoint is specifically set to provide protection against overpressurization (Ref. 5). The safety analyses for both the high pressure trip and the RCS pressurizer safety valves are performed using conservative assumptions relative to pressure control devices.
More specifically, no credit is taken for operation of the following:
- a. Pressurizer power operated relief valves (PORVs);
- b. Steam Generator (SG) PORVs;
- c. Steam Dump System;
- d. Rod Control System;
- e. Pressurizer Level Control System; or
- f. Pressurizer spray valves.
SAFETY LIMITS The maximum transient pressure allowed in the RCS pressure vessel under the ASME Code,Section III, is 110% of design pressure. The maximum transient pressure allowed in the RCS piping, valves, and fittings under ASME Code Section III (Ref. 2) is 120% of design pressure.
The most limiting of these two allowances is the 110% of design pressure; therefore, the SL on maximum allowable RCS pressure is 2735 psig.
APPLICABILITY SL 2.1.2 applies in MODES 1, 2, 3, 4, and 5 because this SL could be approached or exceeded in these MODES due to overpressurization events. The SL is not applicable in MODE 6 because the reactor vessel head closure bolts are not fully tightened, making it unlikely that the RCS can be pressurized.
McGuire Units I and 2 B 2.1.2-2 Revision No. 109
. BASES SAFETY LIMIT If the RCS pressure SL is violated when the reactor is in MODE 1 or 2, VIOLATIONS the requirement is to restore compliance and be in MODE 3 within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
Exceeding the RCS pressure SL may cause immediate RCS failure and create a potential for radioactive releases in excess of 10 CFR 50.67, "Accident Source Term," limits (Ref. 4).
The allowable Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> recognizes the importance of reducing power level to a MODE of operation where the potential for challenges to safety systems is minimized.
If the RCS pressure SL is exceeded in MODE 3, 4, or 5, RCS pressure must be restored to within the SL value within 5 minutes. Exceeding the RCS pressure SL in MODE 3, 4, or 5 is more severe than exceeding this SL in MODE 1 or 2, since the reactor vessel temperature may be lower and the vessel material, consequently, less ductile. As such, pressure must be reduced to less than the SL within 5 minutes. The action does not require reducing MODES, since this would require reducing temperature, which would compound the problem by adding thermal gradient stresses to the existing pressure stress.
. REFERENCES 1. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28.
- 2. ASME, Boiler and Pressure Vessel Code,Section III, 1971 Edition, Winter 1971 Addenda.
- 3. ASME Code for Operation and Maintenance of Nuclear Power Plants.
- 4. 10 CFR 50.67, "Accident Source Term."
- 5. UFSAR, Section 7.2.
McGuire Units 1 and 2 B 2.1.2-3 Revision No. 109
AVS B 3.6.10 B 3.6 CONTAINMENT SYSTEMS B 3.6.10 Annulus Ventilation System (AVS)
BASES BACKGROUND The AVS is required by 10 CFR 50, Appendix A, GDC 41, "Containment Atmosphere Cleanup" (Ref. 1), to ensure that radioactive materials that leak from the primary containment into the reactor building (secondary containment) following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment.
The containment has a secondary containment called the reactor building, which is a concrete structure that surrounds the steel primary containment vessel. Between the containment vessel and the reactor building inner wall is an annulus that collects any containment leakage that may occur following a loss of coolant accident (LOCA) or rod ejection accident. This space also allows for periodic inspection of the outer surface of the steel containment vessel.
The AVS establishes a negative pressure in the annulus between the reactor building and the steel containment vessel. Filters in the system then control the release of radioactive contaminants to the environment.
Reactor building OPERABILITY is required to ensure retention of primary containment leakage and proper operation of the AVS.
The AVS consists of two separate and redundant trains. Each train includes a heater, mechanical demister, a prefilter/ moisture separator, upstream and downstream high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section for removal of radioiodines, and a fan. Ductwork, valves and/or dampers, and instrumentation also form part of the system. The heaters and mechanical demisters function to reduce the moisture content of the airstream to less than 70% relative humidity. A second bank of HEPA filters follows -the adsorber section to collect carbon fines and provide backup in case of failure of the main HEPA filter bank. Only the upstream HEPA filter and the charcoal adsorber section are credited in the analysis. The system initiates and maintains a. negative air pressure in the reactor building annulus by means of filtered exhaust ventilation of the reactor building annulus following receipt of a Phase B isolation signal. The system is described in Reference 2.
The prefilters remove large particles in the air, and the moisture separators remove entrained water droplets present, to prevent excessive loading of the HEPA filters and charcoal absorbers. Heaters are included Revision No. 109 Units 1 McGuire Units and 2 1 and 2 B 3.6.10-1 B 3.6.10-1 Revision No. 109
AVS B, 3.6.10 BASES BACKGROUND (continued) to reduce the relative humidity of the airstream. Continuous operation of each train,_for at least 10_hours -per month,-with -heaters on,- reduces.
moisture buildup on their HEPA filters and adsorbers. The mechanical demisters cool the air to keep the charcoal beds from becoming too hot due to absorption of fission product.
The AVS reduces the radioactive content in the annulus atmosphere following a DBA. Loss of the AVS could cause site boundary doses, in the event of a DBA, to exceed the values given in the licensing basis.
APPLICABLE The AVS design basis is established by the consequences of the limiting SAFETY ANALYSES DBA, which is a LOCA. The accident analysis (Ref. 3) assumes that only one train of the AVS is functional due to a single failure that disables the other train. The accident analysis accounts for the reduction in airborne radioactive material provided by the remaining one train of this filtration system. The amount of fission products available for release from containment is determined for a LOCA.
The modeled AVS actuation in the safety analyses is based upon a worst case response time following a Phase B isolation signal initiated at the limiting setpoint. The total response time, from exceeding the signal setpoint to attaining the negative pressure of 0.5 inch water gauge in the reactor building annulus, is 22 seconds. The pressure then goes to -3.5 inches water within 48 seconds after the start signal is initiated. At this point the system switches into its recirculation mode of operation and pressure may increase to -0.5 inches water within 278 seconds but will not go above -0.5 inches water. This response time is composed of signal delay, diesel generator startup and sequencing time, system startup time, and time for the system to attain the required pressure after starting.
The AVS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).
LCO In the event of a DBA, one AVS train is required to provide the minimum particulate iodine removal assumed in the safety analysis. Two trains of the AVS must be OPERABLE to ensure that at least one train will operate, assuming that the other train is disabled by a single active failure. .,
Revision No. 109 Units 1 McGuire Units and 2 1 and 2 B 3.6.10-2 B 3.6.10-2 Revision No. 109
AVS B 3.6.10 BASES APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could lead to fission product release to containment that leaks to the reactor building. The large break LOCA, on which this system's design is based, is a full power event. Less severe
-LOCAs and-leakage still -require-the system to-be-OPERABLE-throughout-these MODES. The probability and severity of a LOCA decrease as core power and Reactor Coolant System pressure decrease. With the reactor shut down, the probability of release of radioactivity resulting from such an accident is low.
In MODES 5 and 6, the probability and consequences of a DBA are low due to the pressure and temperature limitations in these MODES. Under these conditions, the AVS is not required to be OPERABLE.
ACTIONS A.1 With one AVS train inoperable, the inoperable train must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant AVS train and the low probability of a DBA occurring during this period. The Completion Time is adequate to make most repairs.
B.1 and B.2 With one or more AVS heaters inoperable, the heater must be restored to OPERABLE status within 7 days. Alternatively, a report must be initiated within 7 days in accordance with Specification 5.6.6, which details the reason for the heater's inoperability and the corrective action required to return the heater to OPERABLE status.
The heaters do not affect OPERABILITY of the AVS filter train because charcoal adsorber efficiency testing is performed at 30 0 C and 95%
relative humidity. The accident analysis shows that site boundary radiation doses are within 10 CFR 50.67 (Ref. 6) limits during a DBA LOCA under these conditions.
C.1 and C.2 If the AVS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within Revision No. 109 McGuire Units and 2 Units 11 and 2 B 3.6.10-3 B 3.6.10-3 Revision No. 109
AVS B 3.6.10 BASES ACTIONS (continued) 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on
operatirigexperience, -to reach the required. plant conditions-from-full.
power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.6.10.1 REQUIREMENTS Operating each AVS train from the control room with flow through the HEPA filters and activated carbon adsorbers ensures that all trains are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on for
> 10 continuous hours eliminates moisture on the adsorbers and HEPA filters. Experience from filter testing at operating units indicates that the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> period is adequate for moisture elimination on the adsorbers and HEPA filters. Inoperable heaters are addressed by Required Actions B.1 and B.2. The inoperability of heaters between required performances of this surveillance does not affect OPERABILITY of each AVS train. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls, the two train redundancy available, and the iodine removal capability of the Containment Spray System and Ice Condenser.
SR 3.6.10.2 This SR verifies that the required AVS filter testing is performed in accordance with -the Ventilation Filter Testing Program (VFTP). The AVS filter tests are in accordance with Regulatory Guide 1.52 (Ref. 5) with exceptions as noted in the UFSAR. The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.
SR 3.6.10.3 The automatic startup on a Containment Phase B Isolation signal ensures that each AVS train responds properly. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency.
Mc~ure nits1 ad 2 3..10- Reisio No 10 McGuire Units 1 and 2 B 3.6.10-4 Revision No. 109
AVS B 3.6.10 BASES SURVEILLANCE REQUIREMENTS (continued)
Therefore the Frequency was concluded to be acceptable from a
.refiability-standpoint.. Furthermore, the SR interval was-developed .
considering that the AVS equipment OPERABILITY is demonstrated at a 31 day Frequency by SR 3.6.10.1.
SR 3.6.10.4 The AVS filter cooling electric motor-operated bypass valves are tested to verify OPERABILITY. The valves are normally closed and may need to be opened to initiate miniflow cooling through a filter unit that has been shutdown following a DBA LOCA. Miniflow cooling may be necessary to limit temperature increase in the idle filter train due to decay heat from captured fission products. The 18 month Frequency is considered to be acceptable based on valve reliability and design, and the fact that operating experience has shown that the valves usually pass the Surveillance when performed at the 18 month Frequency.
SR 3.6.10.5 The proper functioning of the fans, dampers, filters, adsorbers, etc., as a system is verified by. the ability of each train to produce the required system flow rate. The 18 month Frequency is consistent with Regulatory Guide 1.52 (Ref. 5) guidance for functional testing.
REFERENCES 1. 10 CFR 50, Appendix A, GDC 41.
- 2. UFSAR, Section 6.2.
- 3. UFSAR, Chapter 15.
- 4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
- 5. Regulatory Guide 1.52, Revision 2.
- 6. 10 CFR 50.67, "Accident Source Term."
Revision No. 109 BB 3.6.10-5 McGuire Units 1 and 2 McGuire Units 1 and 2 3.6.10-5 Revision No. 109
CRAVS B 3.7.9 B 3.7 PLANT SYSTEMS B 3.7.9 Control Room Area Ventilation System (CRAVS)
BASES BACKGROUND The CRAVS provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke.
The CRAVS consists of two independent, redundant trains that draw in filtered outsideair and mix this air with conditioned air recirculating through the Control Room Envelope (CRE). Each outside air pressure filter train consists of a prefilter, a high efficiency particulate air (HEPA) filter, an. activated charcoal absorber section for removal of gaseous activity (principally iodines), and a fan. Ductwork, valves or dampers, doors, barriers, and instrumentation also form part of the system, as well as prefilters to remove water droplets from the air stream. A second bank of HEPA filters follows the absorber section to collect carbon fines and provides backup in case of failure of the main HEPA filter bank.
The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. The CRE is protected during normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations, and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (DBA) consequences to CRE occupants. The CRE and its boundary are defined in the Control Room Envelope Habitability Program.
The CRAVS is an emergency system. During normal operation the CRE is provided with 100% recirculated air and the outside air pressure filter train is in the standby mode. Upon receipt of the actuating signal(s), the CRE is provided with fresh air through outside air intakes and is circulated through the system filter trains. The prefilters remove any large particles in the air, and any entrained water droplets present, to prevent excessive loading of the HEPA filters and charcoal adsorbers. Continuous operation of each train for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> per month, with the heaters on, reduces moisture buildup on the HEPA filters and adsorbers. The heater is important to the effectiveness of the charcoal adsorbers.
McGuire Units 1 and 2 B 3.7.9-1 Revision No. 109
CRAVS B 3.7.9 BASES BACKGROUND (continued)
Actuation of the CRAVS places the system in the emergency mode of operation, depending on the initiation signal. The emergency radiation state initiates pressurization and filtered ventilation of the air supply to the CRE. Pressurization of the CRE minimizes infiltration of unfiltered air from the surrounding areas adjacent to the CRE boundary.
The air entering the outside air intakes is continuously monitored by radiation detectors. The detector output above the setpoint will alarm in the Control Room.
A single CRAVS train can adequately pressurize the CRE relative to atmospheric pressure. The CRAVS operation in maintaining the CRE habitable is discussed in the UFSAR, Section 6.4 (Ref. 1).
Redundant supply and recirculation trains provide the required filtration should an excessive pressure drop develop across the other filter train.
Normally open outside air intake isolation dampers are arranged in series pairs so that the failure of one damper to shut will not result in a breach of isolation. The CRAVS is designed in accordance with Seismic Category I requirements.
The CRAVS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a Design Basis Accident (DBA) without exceeding a 5 rem Total Effective Dose Equivalent (TEDE).
There are components that have nomenclature associated with the CRAVS but do not perform any function that impacts the control room.
These components include the Control Room Area Air Handling units, the Switchgear Air Handling units" the Battery Room Exhaust Fans and the associated ductwork, dampers, and instrumentation. These components share the CRACWS with the CRAVS but are not governed by LCO 3.7.9.
APPLICABLE The CRAVS components are arranged in redundant, safety related SAFETY ANALYSES ventilation trains. The CRAVS provides airborne radiological protection for the CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis accident - fission product release presented in the UFSAR, Chapter 15 (Ref. 2).
The CRAVS provides protection from smoke and hazardous chemicals to the CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref. 1). The evaluation of a Revision No. 109 and 22 Units 11 and McGuire Units B 3.7.9-2 B 3.7.9-2 Revision No. 109
CRAVS B 3.7.9 BASES APPLI CABLE SAFETY ANALYSES (continued) smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the safe shutdown facility (Ref. 3).
The worst case single active failure of a component of the CRAVS, assuming a loss of offsite power, does not impair the ability of the system to perform its design function.
The CRAVS satisfies Criterion 3 of 10 CFR 50.36.
LCO Two independent and redundant CRAVS trains are required to be OPERABLE to ensure that at least one is available if a single active failure disables the other train. Total system failure, such as from a loss of both ventilation trains or from an inoperable CRE boundary, could result in exceeding a dose of 5 rem TEDE to the CRE occupants in the event of a large radioactive release.
Each CRAVS train is considered OPERABLE when the individual components necessary to limit CRE occupant exposure are OPERABLE.
A CRAVS train is OPERABLE when the associated:
- a. An Outside Air Pressure Filter Train fan and a Control Room Air Handling unit are OPERABLE;
- b. HEPA filters and charcoal adsorbers are not excessively restricting flow, and are capable of performing their filtration functions; and
In order for the CRAVS trains to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that CRE occupants are protected from hazardous chemicals and smoke.
The CRAVS is shared between the two units. The system must be OPERABLE for each unit when that unit is in the MODE of Applicability.
Additionally, both normal and emergency power must also be OPERABLE because the system is shared. If a CRAVS component becomes inoperable, or normal or emergency power to a CRAVS component becomes inoperable, then the Required Actions of this LCO McGuire Units 1 and 2 B 3.7.9-3 Revision No. 109
CRAVS B 3.7.9 BASES LOC (continued) must be entered independently for each unit that is in the MODE of applicability of the LCO.
The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area.
For other openings, these controls should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated.
APPLICABILITY In MODES 1, 2, 3,.4, 5, and 6, and duringmovement of irradiated fuel assemblies and during CORE ALTERATIONS, the CRAVS must be OPERABLE to ensure that the CRE will remain habitable during and following a DBA.
During movement of irradiated fuel assemblies and CORE ALTERATIONS, the CRAVS must be OPERABLE to cope with the release from a fuel handling accident.
ACTIONS A.-1 When one CRAVS train is inoperable, for reasons other than an inoperable CRE boundary, action must be taken to restore OPERABLE status within 7 days. In this Condition, the remaining OPERABLE CRAVS train is adequate to perform the CRE occupant protection function. However, the overall reliability is reduced because a failure in the OPERABLE CRAVS train could result in loss of CRAVS function. The 7 day Completion Time is based on the low probability of a DBA occurring during this time period, and ability of the remaining train to provide the required capability.
McGuire Units 1 and 2 B 3.7.9-4 Revision No. 109
CRAVS B 3.7.9 BASES ACTIONS (Continued)
.. 1, B.2, arid B.3 If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of DBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days.
During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposure will not exceed the calculated dose of the licensing basis analyses of DBA consequences, and the CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable based on the low probability of a DBA occurring during this time period, and the use of mitigating actions. The 90 day Completion Time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor'and maintain it in a safe shutdown condition in the event of a DBA. In addition, the 90 day Completion Time is a reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.
C.1 and C.2 In MODE 1, 2, 3, or 4, if the inoperable CRAVS train or the CRE boundary cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes accident risk. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
McGuire Units.1 and 2 B 3.7.9-5 Revision No. 109
CRAVS B 3.7.9 BASES ACTIONS (Continued)
D*1,- D.21*, and'D.2.2 In MODE 5 or 6, or during movement of irradiated fuel assemblies, or during CORE ALTERATIONS, if the inoperable CRAVS train cannot be restored to OPERABLE status within the required Completion Time, action must be taken to immediately place the OPERABLE CRAVS train in the emergency mode. This action ensures that the remaining train is OPERABLE, that no failures preventing automatic actuation will occur, and that any active failure would be readily detected. An alternative to Required Action D.1 is to immediately suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.
E.1 and E.2 In MODE 5 or 6, or during movement of irradiated fuel assemblies, or during CORE ALTERATIONS, with two .CRAVS trains inoperable or with one or more CRAVS trains inoperable due to an inoperable CRE boundary, action must be taken immediately to suspend activities that could result in a release of radioactivity that might enter the control room.
This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.
F. 1 If both CRAVS trains are inoperable in MODE 1, 2, 3, or 4 for reasons other than an inoperable CRE boundary (i.e., Condition B), the CRAVS may not be capable of performing the intended function and the unit is in a condition outside the accident analyses. Therefore, LCO 3.0.3 must be entered immediately.
G.1 and G.2 Action G.1 allows one or more CRAVS heater inoperable, with the heater restored to OPERABLE status within 7 days. Alternatively, Action G.2 requires if the heater is not returned to OPERABLE within the 7 days, a report to be initiated per Specification 5.6.6, which details the reason for the heater's inoperability and the corrective action required to return the heater to OPERABLE status.
The heaters do not affect OPERABILITY of the CRAVS filter train because charcoal absorber efficiency testing is performed at 300C and 90
% relative humidity. The accident analysis shows that control room McGuire Units 1 and 2 B 3.7.9-6 Revision No. 109
CRAVS B 3.7.9 BASES ACTIONS (Continued) radiation doses are within 10 CFR 50.67 (Ref. 8) liri-its during a DBA LOCA under these conditions.
SURVEILLANCE SR 3.7.9.1 REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly. As the environment and normal operating conditions on this system are not too severe, testing each train once every month provides an adequate check of this system. Monthly heater operations dry out any moisture accumulated in the charcoal from humidity in the ambient air. Systems with heaters must be operated from the control room for >_10 continuous hours with the heaters energized and flow through the HEPA filters and charcoal adsorbers. Inoperable heaters are addressed by Required Actions G.A and G.2. The inoperability of heaters between required performances of this surveillance does not affect OPERABILITY of each CRAVS train. The 31 day Frequency is based on the reliability of the equipment and the two train redundancy..
SR 3.7.9.2 This SR verifies that the required CRAVS testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The CRAYS filter tests are in accordance with Regulatory Guide 1.52 (Ref. 4).
The VFTP includes testing the performance of the HEPA filter, charcoal adsorber efficiency, minimum flow rate, and the physical properties of the activated charcoal. Specific test Frequencies and additional information are discussed in detail in the VFTP.
SR 3.7.9.3 This SR verifies that each CRAVS train starts and operates with flow through the HEPA filters and charcoal adsorbers on an actual or simulated actuation signal. The Frequency of 18 months is based on industry operating experience.
SR 3.7.9.4 This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.
McGuire Units 1 and 2 B 3.7.9-7 Revision No. 109
CRAVS B 3.7.9 BASES SURVEILLANCE REQUIREMENTS (continued)
The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of DBA consequences is no more that 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke. This SR verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of DBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be entered. Required Acton B.3 allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 5) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 6). These compensatory measures may also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 7).
Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis DBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage
.test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.
Revision No. 109 McGuire Units McGuire and 2 1 and Units 1 2 B 3.7.9-8 B 3.7.9-8 Revision No. 109
CRAVS B 3.7.9 BASES REFERENCES 1. UFSAR, Section 6.4.
- 2. UFSAR, Chapter 15.
- 3. UFSAR, Section 9.5.
- 4. Regulatory Guide 1.52, Rev. 2.
- 5. Regulatory Guide 1.196, Rev. 1.
- 6. NEI 99-03, June 2001, "Control Room Habitability Assessment Guidance".
- 7. Letter from Eric Leeds (NRC) to James Davis (NEI) dated January 30, 2004, "NEI Draft White Paper, Use of GL 91-18-Process and Alternate Source Terms in the Context of Control Room Habitability."
- 8. 10 CFR 50.67, "Accident Source Term."
McGuire Units 1 and 2 B 3.7.9-9 Revision No. 109
ABFVES B 3.7.11 B 3.7 PLANT SYSTEMS
-B 3.7.11 ---Auxiliary Building Filtere-d"Vetilation Exhi-o-st-Sy-tef-(AB FVES)-
BASES BACKGROUND The ABFVES filters air from the area of the active ECCS components during the recirculation phase of a loss of coolant accident (LOCA).
The ABFVES, in conjunction with other normally operating systems, also provides environmental control of temperature and humidity in the ECCS pump room area and the auxiliary building.
The ABFVES consists of a system, made up of prefilter, a high efficiency particulate air (HEPA) filter, a carbon adsorber section for removal of gaseous activity (principally iodines), and two fans.
Ductwork, valves or dampers, and instrumentation also form part of the system. The system initiates filtered ventilation of the pump room following receipt of a safety injection (SI) signal.
The ABFVE systems are designed to be shared between units. Each unit's system is constructed with two 50% capacity fans providing flow to a 100% capacity filter package. With this design, both Units l's and Units 2's ABFVE systems are required to be OPERABLE with either unit in MODES 1, 2, 3, or 4.
The ABFVES is a standby system, aligned to bypass the system HEPA filters and carbon adsorbers. During emergency operations, the ABFVES dampers are realigned to begin filtration. Upon receipt of the actuating Engineered Safety Feature Actuation System signal(s), air is pulled from the mechanical penetration area and the ECCS pump rooms, and the stream of ventilation air discharges through the system filters. The prefilters remove any large particles in the air, and any entrained water droplets present, to prevent excessive loading of the HEPA filters and carbon adsorbers.
The ABFVES was not initially designed as a safety related system.
However, during initial plant licensing, the ABFVES was re-classified as an engineered safety feature (ESF) atmosphere cleanup system and partially upgraded to meet most of the recommendations of Regulatory Guide 1.52. A comparison of the current ABFVES design to Regulatory Guide 1.52 (Ref. 6) is presented in UFSAR Table 9-38 (Ref. 8) and is discussed in UFSAR Section 9.4 (Ref. 1).
McGuire Units 1 and 2 B 3.7.11 -1 Revision No. 109
ABFVES B 3.7.11 BASES BACKGROUND (Continued),
The ABFVES is discussed in the UFSAR, Sections 9.4, 12.2, and 15.6.5 (Refs. 1,2, and 3, respectively) since it may be used for normal, as well as post accident, atmospheric cleanup functions.
APPLICABLE The design basis, of the ABFVES is established by the large break SAFETY ANALYSES LOCA. The system evaluation assumes a passive failure of the ECCS outside containment, such as an SI pump seal failure, during the recirculation mode. In such a case, the system limits radioactive release to within the 10 CFR 50.67 (Ref. 4) limits, or the NRC staff approved licensing basis (e.g., a specified fraction of Reference 4 limits)., The analysis of the effects and consequences of a large break LOCA is presented in Reference 3. The ABFVES also actuates following a small break LOCA, in those cases where'the ECCS goes into the recirculation mode of long term cooling, to clean up releases of smaller leaks, such as from valve stem packing.
Two types of system failures are considered in the accident analysis: complete loss of function, and excessive LEAKAGE.
Either type of failure may result in a lower efficiency of removal for any gaseous and particulate activity released to the ECCS pump rooms following a LOCA.
The ABFVES satisfies Criterion 3 of 10 CFR 50.36 (Ref. 5).
LCO The ABFVES is required to be OPERABLE with either unit in MODES 1, 2, 3, or 4. Total system failure could result in the atmospheric release from the ECCS pump room exceeding 10 CFR 50.67 limits in the event of a Design Basis Accident (DBA).
ABFVES is consi dered OPERABLE when the individual components necessary to maintain the ECCS pump room filtration are OPERABLE in both units systems.
An ABFVES is considered OPERABLE when its associated:
- a. Fans in configuration as described below are OPERABLE:
Both fans OPERABLE in any one set of fans listed below:
1Aand lB, or 2A and 2B, or 1A and 2A, or 1B and 2B McGuire Units 1 and 2 B 3.7.11-2 Revision No. 109
ABFVES B 3.7.11 BASES LCO (continued)
Use of anyot-her two-fan .ombina-tion requires surveillance testing in that configuration prior to taking credit for that combination.
- b. HEPA filter and carbon adsorbers are not excessively restricting flow, and are capable of performing their filtration functions; and
The ABFVES is shared between the two units. The system must be OPERABLE for each unit when that unit is in the MODE of Applicability. Additionally, both normal and emergency power must-also be OPERABLE because the system is shared. If a ABFVES component becomes inoperable, or normal or emergency power to a ABFVES component becomes inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in the MODE of applicability of the LCO.
The LCO is modified by a NOTE allowing the Auxiliary Building pressure boundary to be opened intermittently under administrative controls. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls consist of stationing a dedicated individual at the opening who is in continuous communication with the control room. This individual will have a method to rapidly close the opening when a need for Auxiliary Building pressure boundary isolation is indicated.
APPLICABILITY Either unit in MODES 1, 2, 3, and 4, the ABFVES is required to be OPERABLE consistent with the OPERABILITY requirements of the ECCS.
Both units in MODE 5 or 6, the ABFVES is not required to be OPERABLE since the ECCS is not required to be OPERABLE.
ACTIONS A.1 With one unit's ABFVES inoperable, action must be taken to restore OPERABLE status within 7 days. During this time, the McGuire Units 1 and 2 B 3.7.11-3 Revision No. 109
ABFVES B 3.7.11 BASES ACTIONS (continued)
Qremaining OPERABLE unit's system is adequate to perform the ABFVES function. One unit's system of ABFVES may be made inoperable from, but not limited to, the filter assembly, fans, flowpath, or the ability to maintain the required negative 0.125 inches of water gauge (wg) for the ECCS pump rooms relative to atmospheric pressure.
The'7 day Completion Time is appropriate because the risk contribution is less than that for the ECCS (72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time), and this system is not a direct support system for the ECCS. The 7 day Completion Time is based on the low probability of a DBA occurring during thistime period, and ability of the remaining unit's system to provide the required capability.
B.1-With both unit's ABFVE systems inoperable, action must be taken to restore to OPERABLE status one unit's ABFVE system within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is based on an adequate period of time to determine the cause of the inoperability and affect repairs without the need of shutting down both units. In addition, the probability of a DBA is low for this short period of time.
If the Auxiliary Building pressure boundary is inoperable such that the ABFVES trains cannot establish or maintain the required pressure, action must be taken to restore an OPERABLE Auxiliary Building pressure boundary within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. During the period that the Auxiliary Building pressure boundary is inoperable, appropriate compensatory measures [consistent with the intent, as applicable, of GDC 19, 60, 64 and 10 CFR Part 50.67] should be utilized to protect plant personnel from potential hazards such as radioactive contamination, toxic chemicals, smoke, temperature and relative humidity, and physical security. Preplanned measures should be available to address these concerns for intentional and unintentional entry into the condition.
C.1 and C.2 If the ABFVES cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, McGuire Units 1 and 2 B 3.7.11-4 Revision No. 109
ABFVES B 3.7.11 BASES ACTIONS (continued) based.on.orperating .xpqrience,Jto. re'ach the require'd ..unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SURVEILLANCE SR 3.7.11.1 REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly. As the environment and normal operating conditions on this system are not severe, testing each train once a month provides an adequate check on this system. Systems without heaters need only be operated from the control room for
_>15 minutes with flow through the HEPA filters and charcoal adsorbers to demonstrate the function of the system. The 31 day Frequency is based on the known reliability of equipment.
SR 3.7.11.2 This SR verifies that the required ABFVES testing is performed in accordance with the Ventilation Filter Testing Program (VFTP).
The ABFVES filter tests are in accordance with Reference 4. The VFTP includes testing HEPA filter performance, carbon adsorbers efficiency, minimum system flow rate, and the physical properties of the carbon (general use and following specific operations).
Specific test Frequencies and additional information are discussed in detail in the VFTP.
SR 3.7.11.3 This SR verifies that ABFVES starts and operates with flow through the HEPA filters and charcoal adsorbers on an actual or simulated actuation signal. The 18 month Frequency is consistent.
with that specified in Regulatory Guide 1.52 (Ref. 6).
SR 3.7.11.4 This SR verifies the integrity of the ECCS pump room enclosure.
The ability of the ECCS pump room to maintain a negative pressure, with respect to potentially uncontaminated adjacent areas; is periodically tested to verify proper functioning of the ABFVES. During the post accident mode of operation, the ABFVES is designed to maintain a slight negative pressure in the ECCS pump room area, with respect to adjacent areas, to prevent unfiltered LEAKAGE. The ABFVES is designed to maintain a
< -0.125 inches water gauge relative to atmospheric pressure.
McGuire Units 1 and 2 B 3.7.11-5 Revision No. 109
ABFVES B 3.7.11 BASES SURVEILLANCE REQUIREMENTS (continued)
This SR is required to be performed for each fan combination (1A and 1B, 2A and 2B, 1A and 2A, 1B and 2B) described in the LCO Bases. The Frequency of 18 months is consistent with the guidance provided in NUREG-0800, Section 6.5.1 (Ref. 7).
An 18 month Frequency on a STAGGERED TEST BASIS is consistent with that specified in Reference 6.
REFERENCES 1. UFSAR, Section 9.4.
- 2. UFSAR, Section 12.2.
- 3. UFSAR, Section 15.6.5.
- 4. 10 CFR 50.67, "Accident Source Term.'
- 5. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
- 6. Regulatory Guide 1.52 (Rev. 2).
- 7. NUREG-0800, Section 6.5.1, Rev. 2, July 1981.
- 8. UFSAR, Table 9-38.
McGuire Units 1 and 2 B 3.7.1 1-6 Revision No. 109
Containment Spray System B 3.6.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.6 Containment Spray System BASES BACKGROUND The Containment Spray System provides containment atmosphere cooling to limit post accident pressure and temperature in containment to less than the design values. Reduction of containment pressure and the iodine removal capability of the spray reduce the release of fission product radioactivity from containment to the environment, in the event of a Design Basis Accident (DBA). The Containment Spray System is designed to meet the requirements of 10 CFR 50, Appendix A, GDC 38, "Containment Heat Removal," GDC 39, "Inspection of Containment Heat Removal Systems,' GDC 40, "Testing of Containment Heat Removal Systems," GDC 41, "Containment Atmosphere Cleanup," GDC 42, "Inspection of Containment Atmosphere Cleanup Systems," and GDC 43, "Testing of Containment Atmosphere Cleanup Systems" (Ref. 1).
The Containment Spray System consists of two separate trains of equal capacity, each capable of meeting the system design basis spray coverage. Each train includes a containment spray pump, one containment spray heat exchanger, spray headers, nozzles, valves, and piping. Each train is powered from a separate Engineered Safety Feature (ESF) bus. The refueling water storage tank (RWST) supplies borated water to the Containment Spray System during the injection phase of operation. In the recirculation mode of operation, containment spray pump suction is transferred from the RWST to the containment recirculation sump(s).
The diversion of a portion of the recirculation flow from each train of the Residual Heat Removal (RHR) System to additional redundant spray headers completes the Containment Spray System heat removal capability. Each RHR train is capable of supplying spray coverage, if required, to supplement the Containment Spray System.
The Containment Spray System and RHR System provide a spray of cold or subcooled borated water into the upper containment volume to limit the containment pressure and temperature during a DBA. The RWST solution temperature is an important factor in determining the heat removal capability of the Containment Spray System during the injection phase. In the recirculation mode of operation, heat is removed from the containment sump water by the Containment Spray System and RHR heat exchangers. Each train of the Containment Spray System, supplemented by a train of RHR spray, provides adequate spray coverage to meet the system design requirements for containment heat removal.
McGuire Units 1 and 2 B 3.6.6-1 Revision No. 110
Containment Spray System B 3.6.6 BASES BACKGROUND (continued)
For-the -hypothetical double-ended rupture of a-Reactor-Goolant -System-pipe, the pH of the sump solution (and, consequently, the spray solution) is raised to at least 8.0 within one hour of the onset of the LOCA. The resultant pH of the sump solution is based on the mixing of the RCS fluids, ECCS injection fluid, and the melted ice which are combined in the sump.
The alkaline pH of the containment sump water minimizes the evolution of iodine and the occurrence of chloride and caustic stress corrosion on mechanical systems and components exposed to the fluid.
The Containment Spray System is actuated either automatically by a containment pressure high-high signal or manually. An automatic actuation opens the containment spray pump discharge valves, starts the two containment spray pumps, and begins the injection phase. A manual actuation of the Containment Spray System requires the operator to actuate two separate train related switches on the main control board to begin the same sequence of two train actuation. The injection phase continues until an RWST level Low-Low alarm is received. The Low-Low alarm for the RWST signals the operator to manually align the system to the recirculation mode. The Containment Spray System in the recirculation mode maintains an equilibrium temperature between the containment atmosphere and the recirculated sump water. Operation of the Containment Spray System in the recirculation mode is controlled by the operator in accordance with the emergency operation procedures.
The RHR spray operation is initiated manually, when required by the emergency operating procedures, after the Emergency Core Cooling System (ECCS) is operating in the recirculation mode. The RHR sprays are available to supplement the Containment Spray System, if required, in limiting containment pressure. This additional spray capacity would typically be used after the ice bed has been depleted and in the event that containment pressure rises above a predetermined limit. The Containment Spray System is an ESF system. It is designed to ensure that the heat removal capability required during the post accident period can be attained.
The operation of the Containment Spray System, together with the ice condenser, is adequate to assure pressure suppression subsequent to the initial blowdown of steam and water from a DBA. During the post blowdown period, the Air Return System (ARS) is automatically started.
The ARS returns upper compartment air through the divider barrier to the lower compartment. This serves to equalize pressures in containment and to continue circulating heated air and steam through the ice condenser, where heat is removed by the remaining ice.
McGuire Units 1 and 2 B 3.6.6-2 Revision No. 110
Containment Spray System B 3.6.6 BASES BACKGROUND (continued)
The Containment Spray-System- limits-the temperature-and pressure-that-could be expected following a DBA. Protection of containment integrity limits leakage of fission product radioactivity from containment to the environment.
APPLICABLE The limiting DBAs considered relative to containment OPERABILITY SAFETY ANALYSES are the loss of coolant accident (LOCA) and the steam line break (SLB).
The DBA LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients. No two DBAs are assumed to occur simultaneously or consecutively. The postulated DBAs are analyzed, in regard to containment ESF systems, assuming the loss of one ESF bus, which is the worst case single active failure, resulting in one train of the Containment Spray System, the RHR System, and the ARS being rendered inoperable (Ref. 2).
The DBA analyses show that the maximum peak containment pressure results from the LOCA analysis, and is calculated to be less than the containment design pressure. The maximum peak containment atmosphere temperature results from the SLB analysis and was calculated to be within the containment environmental qualification temperature during the DBA SLB. The basis of the containment environmental qualification temperature is to ensure the OPERABILITY of safety related equipment inside containment (Ref. 3).
The modeled Containment Spray System actuation from the containment analysis is based on a response time associated with exceeding the containment pressure high-high signal setpoint to achieving full flow through the containment spray nozzles. A delayed response time initiation provides conservative analyses of peak calculated containment temperature and pressure responses. The Containment Spray System total response time of 120 seconds is composed of signal delay, diesel generator startup, system startup time, and time for the piping to fill.
For certain aspects of transient accident analyses,, maximizing the calculated containment pressure is not conservative. In particular, the ECCS cooling effectiveness during the core reflood phase of a LOCA analysis increases with increasing containment backpressure. For these calculations, the containment backpressure is calculated in a manner designed to conservatively minimize, rather than maximize, the calculated transient containment pressures in accordance with 10 CFR 50, Appendix K (Ref. 4).
McGuire Units 1 and 2 B 3.6.6-:3 Revision No- 110
Containment Spray System B 3.6.6 BASES APPLICABLE SAFETY ANALYSES (continued)
-inadvertent-actuation is precluded by-design features- consisting-of an-additional set of containment pressure sensors which prevents operation when the containment pressure is below the containment pressure control system permissive.
The Containment Spray System satisfies Criterion 3 of 10 CFR 50.36 (Ref.
5).
LCO During a DBA, one train of Containment Spray System is required to provide the heat removal capability assumed in the safety analyses. To ensure that this requirement is met, two containment spray trains must be OPERABLE with power from two safety related, independent power supplies. Therefore, in the event of an accident, at least one train operates.
Each Containment Spray System includes a spray pump, headers, valves, heat exchangers, nozzles, piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the RWST upon an ESF actuation signal and manually transferring suction to the containment sump.
APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment and an increase in containment pressure and temperature requiring the operation of the Containment Spray System.
In MODES 5 and 6, the probability and consequences of these events are reduced because of the pressure and temperature limitations of these MODES. Thus, the Containment Spray System is not required to be OPERABLE in MODE 5 or 6.
ACTIONS A. 1 With one containment spray train inoperable, the affected train must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The components in this degraded condition are capable of providing 100% of the heat removal after an accident. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time was developed taking into account the redundant heat removal and iodine removal capabilities afforded by the OPERABLE train and the low probability of a DBA occurring during this period.
McGuire Units 1 and 2. B 3.6.6-4 Revision No. 110
Containment Spray System B 3.6.6 BASES ACTIONS (continued)
B-l and B.2 If the affected containment spray train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve, this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. The extended interval to reach MODE 5 allows additional time and is reasonable when considering that the driving force for a release of radioactive material from the Reactor Coolant System is reduced in MODE 3.
SURVEILLANCE SR 3.6.6.1 REQUIREMENTS Verifying the correct alignment of manual, power operated, and automatic valves, excluding check valves, in the Containment Spray System provides assurance that the proper flow path exists for Containment Spray System operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since they were verified in the correct position prior to being secured. 'This SR does not require any testing or Valve manipulation. Rather, it involves verification, through a system walkdown or computer status indication, that those valves outside containment and capable of potentially being mispositioned, are in the. correct position.
SR 3.6.6.2 Verifying that each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head ensures that spray pump performance has not degraded during the cycle. Flow and differential head are normal tests of centrifugal pump performance required by the ASME OM Code (Ref. 6). Since the containment spray pumps cannot be tested with flow through the spray headers, they are tested on bypass flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.
McGuire Units 1 and 2 B 3.6.6-5 Revision No. 110
Containment Spray System B 3.6.6 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6:6 .3 and'SR 3.6.6.4 .
These SRs require verification that each automatic containment spray valve actuates to its correct position and each containment spray pump starts upon receipt of an actual or simulated Containment Pressure High-High signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillances were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillances when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
The surveillance of containment sump isolation valves is also required by SR 3.6.6.3. A single surveillance may be used to satisfy both requirements.
SR 3.6.6.5 and SR 3.6.6.6 These SRs require verification that each containment spray pump discharge valve opens or is prevented from opening and each containment spray pump starts or is de-energized and prevented from starting upon receipt of Containment Pressure Control System start and terminate signals. The CPCS is described in the Bases for LCO 3.3.2, "ESFAS." The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage.
SR 3.6.6.7 With the containment spray inlet valves closed and the spray header drained of any solution, low pressure air or smoke can be blown through test connections. The spray nozzles can also be tested using a vacuum blower to induce air flow through each nozzle to verify unobstructed flow. This SR requires verification that each spray nozzle is unobstructed following activities that could cause nozzle blockage. Normal plant operation and activities are not expected to initiate this SR. However, activities such as inadvertent spray actuation that causes fluid flow through the nozzles, major configuration change, or a loss of foreign material control when working within the respective system boundary, may require surveillance performance.
McGuire Units 1 and 2 B 3.6.6-6 Revision No. 110
Containment Spray System B 3.6.6 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 38, GDC 39, GDC 40, GDC 41, GDC 42, and GDC 43.
- 2. UFSAR, Section 6.2.
- 3. 10 CFR 50.49.
- 5. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
- 6. ASME Code for Operation and Maintenance of Nuclear Power Plants.
McGuire Units 1 and 2 R 3.6.6-7 Revision No. 110
AC Sources-Operating B 3.8.1 B-3.8 ELECTRICAL P0,WE_R_.SYSTEMS _.
B 3.8.1 AC Sources-Operating BASES BACKGROUND The unit Essential Auxiliary or Class 1 E AC Electrical Power Distribution System AC sources consist of the offsite power sources (preferred power sources, normal and alternate(s)), and the onsite standby power sources (Train A and Train B. diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.
The onsite Class 1 E AC Distribution System is divided into redundant load groups (trains) so that the loss of any one group does not prevent the minimum safety functions from being performed. Each train has connections to two preferred offsite power sources and a single DG.
Offsite power is supplied to the unit switchyard(s) from the transmission network by two transmission lines. From the switchyard(s), two electrically and physically separated circuits provide AC power, through step down station auxiliary transformers, to the 4.16 kV ESF buses. A detailed description of the offsite power network and the circuits to the Class 1 E ESF buses is found in the UFSAR, Chapter 8 (Ref. 2).
A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to th~e onsite Class 1 E ESF bus(es).
The offsite transmission systems normally supply their respective unit's onsite power supply requirements. However, in the event that one or both buslines of a unit become unavailable, or by operational desire, it is acceptable to supply that unit's offsite to onsite power requirements by aligning the affected 4160V bus of the opposite unit via the standby transformers, SATA and SATB in accordance with Regulatory Guides 1.6 and 1.81 (Ref. 12 and 13). In this alignment, each unit's offsite transmission system could simultaneously supply its own 4160V buses and one (or both) of the buses of the other unit.
Although a single auxiliary transformer (1ATA, 1ATB, 2ATA, 2ATB) is sized to carry all of the auxiliary loads of its unit plus both trains of essential 4160V loads of the opposite unit, the LCO would not be met in this alignment due to separation criteria.
McGuire Units 1 and 2 B 3.8.1 -1 Revision No. 111
AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued)
Each unit's Train A and B 4160V bus must be derived from separate offsite buslines. -The-first offsite-power-supply can. be-derived from any-of the-four buslines (1A, 1 B, 2A, or 2B). The second offsite power supply must not derive its power from the same busline as the first.
Acceptable train and unit specific breaker alignment options are described below:
Unit I A Train
- 1. BL1A-1ATA-1TA-1ATC-1 ETA
- 2. BL1B-1ATB-1TA-1ATC-1ETA
- 3. BLiA-1ATA-1TC-SATA-1 ETA
- 4. BL1 B-1 ATB-1 TC-SATA-1 ETA
- 5. BL2A-2ATA-2TC-SATA-1 ETA
- 6. BL2B-2ATB-2TC-SATA-1 ETA Unit 1 B Train
- 1. BL1B-1ATB-1TD-1ATD-1ETB
- 2. BL1A-1ATA-1TD-1ATD-1ETB
- 3. BL1B-1ATB-1TB-SATB-1ETB
- 4. BL1A-1ATA- 1TB-SATB- 1ETB
- 5. BL2B-2ATB-2TB-SATB-1 ETB
- 6. BL2A-2ATA-2TB-SATB-1 ETB Unit 2 A Train
- 1. B L2A-2ATA-2TA-2ATC-2 ETA
- 2. BL2B-2ATB-2TA-2ATC-2ETA
- 3. BL2A-2ATA-2TC-SATA-2 ETA
- 4. BL2B-2ATB-2TC-SATA-2ETA
- 5. BL1 A-1ATA-1 TC-SATA-2ETA
- 6. BL1 B-1ATB-1TC-SATA-2ETA Unit 2 B Train
- 1. BL2B-2ATB-2TD-2ATD-2ETB
- 2. BL2A-2ATA-2TD-2ATD-2ETB
- 3. BL2B-2ATB-2TB-SATB-2ETB
- 4. BL2A-2ATA-2TB-SATB-2ETB
- 5. BL1 B-1ATB-1TB-SATB-2ETB
- 6. BL1A-iATA-1TB-SATB-2ETB McGuire Units 1 and 2 B 3.8.1-2 Revision No. 111
AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued)
Certain required unit loads are returned to service in a predetermined
. sequence-in
.- order top-prevent overloadingthe._transformer.supplying.offsite.
power to the onsite Class 1 E Distribution System. Typically (via accelerated sequencing), within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.
The onsite standby power source for each 4.16 kV ESF bus is a dedicated DG. DGs A and B are dedicated to ESF buses ETA and ETB, respectively.
A DG starts automatically on a safety injection (SI) signal (i.e., low pressurizer pressure or high containment pressure signals) or on an ESF bus degraded voltage or undervoltage signal (refer to LCO 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation"). After the DG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The DGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips loads from the ESF bus. When the DG is tied to the ESF bus, loads are thensequentially connected to its respective ESF bus by the automatic load sequencer. The.
sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG by automatic load application.
In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a loss of coolant accident (LOCA).
Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the DG in the process.
Typically (via accelerated sequencing), within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.
Ratings for Train A and Train B DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG is 4000 kW with 10% overload permissible for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. The ESF loads that are powered from the 4.16 kV ESF buses are listed in Reference 2.
APPLICABLE The initial conditions of DBA and transient analyses in the UFSAR, SAFETY ANALYSES Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor McGuire Units 1 and 2 B 3.8.1-3 Revision No. 111
AC Sources-Operating B 3.8.1 BASES APPLICABLE SAFETY ANALYSES (continued)
Coolant System (RCS), and containment design limits are not exceeded.
. .... .... . These-limits are-discussed -in-more-detail-in-the Bases forSection_3.2 ......
Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS);
and Section 3.6, Containment Systems.
The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the Accident analyses and is based upon meeting the design basis of the unit. This results in maintaining at least one train of the onsite or offsite AC sources OPERABLE during Accident conditions in the event of:
- a. An assumed loss of all offsite power or all onsite AC power; and
- b. A worst case single failure.
The AC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 6).
LCO Two qualified circuits between the offsite transmission network and the onsite Class 1 E Electrical Power System and separate and independent DGs for each train ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA.
Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing basis for the unit.
In addition, one required automatic load sequencer per train must be OPERABLE.
Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESF buses.
The 4.16 kV essential system is divided into two completely redundant and independent trains designated A and B, each consisting of one 4.16 kV switchgear assembly, two 4.16 kV/600 V load centers, and associated loads.
Normally, each Class 1E 4.16 kV switchgear is powered from its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed in "6.9 kV Normal Auxiliary Power System" in Chapter 8 of the UFSAR (Ref. 2). Additionally, an alternate source of power to each 4.16 kV essential switchgear is provided from the 6.9 kV system via a separate and independent 6.9/4.16 kV transformer. Two transformers are shared between units and provide the capability to supply an alternate source of power to each unit's 4.16 kV essential McGuire Units 1 and 2 B 3.8.1-4 Revision No. 111
AC Sources-Operating B 3.8.1 BASES LCO (continued) switchgear from either unit's 6.9 kV system. A key interlock scheme is
--provided toprecludethe-possibility-ofconnecting the two units together-at either the 6.9 or 4.16 kV level.
Each train of the 4.16 kV Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator to supply the Class 1 E loads required to safely shut down the unit following a design basis accident.
Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This will be accomplished within 11 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until:offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby with the engine at ambient conditions. -
Additional DG capabilities must be demonstrated to meet required Surveillance, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.
Proper sequencing of loads is a function of Sequencer OPERABILITY.
Proper load shedding is a function of DG OPERABILITY. Proper tripping of non-essential loads is a function of AC Bus OPERABILITY (Condition A of Technical Specification 3.8.9).
The AC sources in one train must be separate and independent (to the extent possible) of the AC sources in the other train. For the DGs, separation and independence are complete.
Both normal and emergency power must be OPERABLE for a shared component to be OPERABLE. If normal or emergency power supplying a shared component becomes inoperable, then the Required Actions of the affected shared component LCO must be entered independently for each unit that is in the MODE of applicability of the shared component LCO.
The shared component LCOs are:
3.7.7 - Nuclear Service Water System (NSWS),
3.7.9 - Control Room Area Ventilation System (CRAVS),
3.7.10 - Control Room Area Chilled Water System (CRACWS), and 3.7.11 - Auxiliary Building Filtered Ventilation Exhaust System (ABFVES).
McGuire Units 1 and 2 B 3.8.1-5 Revision No. 111
AC Sources-Operating B 3.8.1 BASES APPLICABILITY The AC sources and sequencers are required to be OPERABLE in
. ......... MODES"1, 2, 3,an-d4toe-s§06re-th.at. .
- a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
- b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC Sources-Shutdown."
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.
There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
A.1 To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.
A.2 Required Action A.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features. These features are powered from the redundant AC electrical power train. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the McGuire Units 1 and 2 B 3.8.1-6 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) availability of decay heat removal capability for all events accompanied by a
-loss of offsite-power and a single failure. -System-designis-such that-the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.
The Completion Time for Required Action A.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:
- a. The train has no offsite power supplying its loads; and
- b. A required feature on the other train is inoperable.
If at any time during the existence of Condition A (one offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.
Discovering no offsite power to one train of the onsite Class 1 E Electrical Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
The remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.
McGuire Units 1 and 2 B 3.8.1 -7 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability. of the remaining ACsources,.a.reasonable-time .for.repairs, and the low probability of a DBA occurring during this period.
The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.
As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage'time "clock."
This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition A was entered.
B.1 To ensure a highly reliable power source remains with an inoperable DG, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered.
B.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related trains. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three McGuire Units 1 and 2 B 3.8.1-8 Revision No. 111
AC Sources-Operating*
B 3.8.1 BASES ACTIONS (continued) independent AFW pumps are required to ensure the availability of decay
.-heat removal capability-forall events accompanied bya.Ioss of offsite..
power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis. Redundant required feature failures consist of inoperable features associated with a train, redundant to the train that has an inoperable DG.
The Completion Time for Required Action B.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:
- a. An inoperable DG exists; and
- b. A required feature on the other train (Train A or Train B) is inoperable.
If at any time during the existence of this Condition (one DG inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.
Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
In this Condition, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
McGuire Units 1 and 2 B 3.8.1-9 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DG(s). If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), the other DG(s) would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure no longer exists, and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s),
performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG.
In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the problem investigation process will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> constraint imposed while in Condition B.
These Conditions are not required to be entered if the inoperability of the DG is due to an inoperable support system, an independently testable component, or preplanned testing or maintenance. If required, these Required Actions are to be completed regardless of when the inoperable DG is restored to OPERABLE status.
According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is reasonable to -
confirm that the OPERABLE DG(s) is not affected by the same problem as the inoperable DG.
B.4 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored McGuire Units 1 and 2 B 3.8.1 -10 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
This-could-lead to-a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failureto- meet the .
LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.
As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition B was entered.
C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is that Regulatory Guide 1.93 (Ref. 7) allows a Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is appropriate. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps.
Single train features, such as turbine driven auxiliary pumps, are not included in the list.
The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:
- a. All required offsite circuits are inoperable; and
- b. A required feature is inoperable.
McGuire Units 1 and 2 B 3.8.1-11 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
Ifat any time during the existence of Condition C (two offsite circuits inoperable)-a required feature becomes inoperable, this-Completion Time.
begins to be tracked.
According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.
Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.
However, two factors tend to decrease the severity of this level of degradation:
- a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and
- b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.
With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importan-ce of maintaining an AC electrical power system capable of meeting its design criteria.
According to Reference 6, with the available offsite AC sources, two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If two offsite sources are restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, power operation continues in accordance with Condition A.
D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are McGuire Units 1 'and 2 B 3.8.1-12 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) modified by a Note to indicate that when Condition D is entered with no
-AC source to any train, -the Conditions and Required Actions for _..
LCO 3.8.9, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of one offsite circuit and one DG, without regard to whether a train is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized train.
According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
E.1 With Train A and Train B DGs inoperable, there are no remaining standby AC sources. Thus, with an assumed los's of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.
According to Reference 7, with both DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
F. 1 The sequencer(s) is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the McGuire Units 1 and 2 B 3.8.1-13 Revision No. 111
AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) sequencer is on the primary success path for most major AC electrically
-powered safety systems-powered from the associated .ESF bus. - -..-.-
Therefore, loss of an ESF bus sequencer affects every major ESF system in the train. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY. This time period also ensures that the probability of an accident (requiring sequencer OPERABILITY) occurring during periods when the sequencer is inoperable is minimal.
G.1 and G.2 If the inoperable AC electric power sources cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems.
H.1 Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.
McGuire Units 1 and 2 B 3.8.1-14 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE The AC sources are designed to permit inspection and testing of all
............-REQUIREMENTS important areas and features, especially-those-that have a standby-.....
function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 9).
Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3) and Regulatory Guide 1.137 (Ref. 11), as addressed in the UFSAR.
Since the McGuire DG manufacturer, Nordberg, is no longer in business, McGuire engineering is the designer of record. Therefore, the term "manufacturer's or vendor's recommendations" is taken to mean the recommendations as determined by McGuire engineering, with specific Nordberg input as it is available, that were intended for the DGs, taking into account the maintenance, operating history, and industry experience, when available.
Where the SRs discussed herein specify voltage and frequency tolerances, the following is applicable. The minimum steady state output voltage of 3740 V is 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90%
of name plate rating. The specified maximum steady state output voltage of 4580 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2Hz, respectively. These values are equal to
+/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).
McGuire Units 1 and 2 B 3.8.1-15 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source, and that appropriate independence of offsite circuits is maintained. The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.
SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and to maintain the unit in a safe shutdown condition.
To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs are modified by a Note (Note 2 for SR 3.8.1:2) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and followed by a warmup period prior to loading.
For the purposes of SR 3.8.1.2 and SR 3.8.1.7 testing, the DGs are started from standby conditions using a manual start, loss of offsite power signal, safety injection signal, or loss of offsite power coincident with a safety injection signal. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.
In order to reduce stress and wear, the manufacturer recommends a modified start in which the DGs are gradually accelerated to synchronous speed prior to loading. These start procedures are the intent of Note 3, which is only applicable when such modified start procedures are recommended by the manufacturer.
SR 3.8.1.7 requires that, at a 184 day Frequency, the DG starts from standby conditions and achieves required voltage and frequency within 11 seconds. The 11 second start requirement supports the assumptions of the design basis LOCA analysis in the UFSAR, Chapter 15 (Ref. 5).
McGuire Units 1 and 2 B 3.8.1-`16 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The 11 second start requirement is not applicable to SR 3.8.1.2 (see
..Note 3)-when a-modified start procedureas described aboveis_.used. If a modified start is not used, the 11 second start requirement of SR 3.8.1.7 applies.
Since SR 3.8.1.7 requires a 11 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This is the intent of Note 1 of SR 3.8.1.2.
The normal 31 day Frequency for SR 3.8.1.2 and the 184 day Frequency for SR 3.8.1.7 are consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.
These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.
SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.
Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.
The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.
This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states t-hat momentary transients, because of changing bus loads, do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
McGuire Units 1 and 2 B 3.8.1-17 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is adequate for approximately 30 minutes of DG operation at full load, which allows for an orderly shutdown of the DG should fuel replenishment to the day tank become unavailable.
The 31 day Frequency is adequate to assure that a sufficient supply of fuel oil is available, since low level alarms are provided and facility operators would be aware of any large uses of fuel oil during this period.
SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventative maintenance. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during the performance of this Surveillance.
SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. This is required to support continuous.operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.
The design of fuel transfer systems is such that pumps operate automatically or may be started manually in order to maintain an adequate volume of fuel oil in the day tanks during or following DG testing. Therefore, a 31 day Frequency is appropriate.
McGuire Units 1 and 2 B 3.8.1-18 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.8.1.7 See SR 3.8.1.2.
SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads.
The 18 month Frequency of the Surveillance is based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems.
SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. For this unit, the single load for each DG and its kilowatt rating is as follows: Nuclear Service Water Pump which is a 576 kW motor. This Surveillance may be accomplished by:
- a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or
- b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.
As required by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the McGuire Units 1 and 2 B 3.8.1-19 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) difference between synchronous speed and the overspeed trip setpoint, or 15% above-synchronous speed,. whichever is lower.
The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 3 seconds specified is equal to 60% of a typical 5 second load sequence interval associated with sequencing of the largest load. The voltage and frequency specified are consistent with the design range of the equipment powered by the DG.
SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c are steady state voltage and frequency values to which the system must recover following load rejection. The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) Table 1.
This Surveillance is performed with the DG connected to its bus in parallel with offsite power supply. The DG is tested under maximum kVAR loading, which is defined as being as close to design basis conditions as practical subject to offsite power conditions. Design basis conditions have been calculated to be greater than 0.9 power factor. During DG testing, equipment ratings are not to be exceeded (i.e., without creating an overvoltage condition on the DG or 4 kV emergency buses, over-excitation in the generator, or overloading the DG emergency feeder while maintaining the power factor greater than or equal to 0.9).
This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.
SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits.
The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
McGuire Units 1 and 2 B 3.8.1-20 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
Although not representative of the design basis inductive loading that the DG.would experience,-a power-factor-of approximately unity- (1.0)- is -used for testing. This power factor is chosen in accordance with manufacturer's recommendations to minimize DG overvoltage during testing.
The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.
This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.
SR 3.8.1.11 As required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies the de-energization of the emergency buses, load shedding from the emergency buses and energization of the emergency buses and blackout loads from the DG. Tripping of non-essential loads is not verified in this test. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.
The DG autostart time of 11 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate .that all starting transients have decayed and stability is achieved.
The requirement to verify the connection and power supply of the emergency bus and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loadinglogic. In certain circumstances, many of these loads.cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable.
This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
McGuire Units 1 and 2 B 3.8.1:-21 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1_9-(Ref. 3)-Table.-1,takes-into consideration-unit -
conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent vWith manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (11 seconds) from the design basis actuation signal (LOCA signal) and operates for _ 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d ensures that the emergency bus remains energized from the offsite electrical power system on an ESF signal without loss of offsite power. This Surveillance also verified the tripping of non-essential loads. Tripping of non-essential loads is verified only once, either in this SR or in SR 3.8.1.19, since the same circuitry is tested in each SR.
The Frequency of 18 months is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1 and takes into consideration unit conditions required to
,perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the. 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.
SR 3.8.1.13 This Surveillance demonstrates that DG non-emergency protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal.
McGuire Units 1 and 2 B*3.8.1-22 Revision No. 111
AC Sources-Operating B 3.8.1 BASES.
SURVEILLANCE REQUIREMENTS (continued)
The non-emergency automatic trips are all automatic trips except:
- a. Engine overspeed;
- b. Generator differential current;
- c. Low lube oil pressure; and
- d. Generator voltage - controlled overcurrent.
The non-emergency trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. .The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG. Currently, DG emergency automatic trips are tested periodically per the station periodic maintenance program.
The 18 month Frequency is consistent with Regulatory Guide 1.9 (Ref. 3)
Table 1, taking into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is not normally performed in MODE 1 or 2, but it may be performed in conjunction with periodic preplanned preventative maintenance activity that causes the DG to be inoperable. This is acceptable provided that performance of the SR does not increase the time the DG would be inoperable for the preplanned preventative maintenance activity.
SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.9, requires demonstration once per 18 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, >_2 hours of which is at a load equivalent from 105% to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
McGuire Units 1 and 2 B 3.8.1-23 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
This Surveillance is performed with the DG connected to its bus in parallel
-with offsite power supply. The DGis tested under maximum kVAR .
loading, which is defined as being as close to design basis conditions as practical subject to offsite power conditions. Design basis conditions have been calculated to be greater than 0.9 power factor. During DG testing, equipment ratings are not to be exceeded (i.e., without creating an overvoltage condition on the DG or 4 kV emergency buses, over-excitation in the generator, or overloading the DG emergency feeder while maintaining the power factor greater than or equal to 0.9).
The load band is provided to avoid routine overloading of the DG.
Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance,.and is intended to be consistent with expected fuel cycle lengths.
This Surveillance is modified by two Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Note 2 allows gradual loading of the DG in accordance with recommendation from the manufacturer.
This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.
SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 11 seconds. The 11 second time is derived from the requirements of the accident analysis to respond to.a design basis large break LOCA. The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1.
This' SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load McGuire Units 1 and 2 B 3.8.1-24 Revision No. 1-11
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) conditions prior to performance of this Surveillance is based on
-manufacturer recommendations for achieving hot -conditions. .Momentary-transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.
SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.11, this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to standby operation when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in standby operation when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.
The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, and takes into consideration unit conditions required to perform the Surveillance. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to standby operation if a LOCA
- actuation signal is received during operation in the test mode. Standby operation is defined as the DG running at rated speed and voltage with the DG output breaker open. These provisions for automatic switchover are required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.13. The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.17.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
McGuire Units 1 and 2 B 3.8.1-25 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The'18 month Frequency is consistent With the recommendations of Regulatory Guide .1.9 (Ref. 3) Table 1, takes'into.consideration unit conditions required to perform the Surveillance, and is intended'to be consistent with expected fuel cycle lengths.
This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
SR 3.8.1.18 Under accident and loss of offsite powerconditions loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The load sequence time interval tolerance in Table 8-16 of Reference 2 ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis-assumptions regarding ESF equipment time delays are not violated.
Table 8-1 of Reference 2 provides a summary of the automatic loading of.
- ESF buses. The sequencing times of Table 8-16 are committed and required for OPERABILITY. The typical 1 minute loading duration seen by the accelerated sequencing scheme is NOT required for OPERABILITY.
Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
SR 3.8.1.19 In the event of a .DBA coincident with a loss of offsite piower, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.
This Surveillance verifies the de-energization of the emergency buses, load shedding from the emergency buses, tripping of non-essential loads and energization of the emergency buses and ESF loads from the DG.
Tripping of non-essential loads is verified only once, either in this SR or in SR 3.8.1.12, since the same circuitry is tested in each SR. In lieu of actual demonstration of connection and loading of loads, testing that McGuire Units 1 and 2 B 3.8.1-26 Revision No. 111
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) adequately shows the capability of the DG system to perform these functions. is acceptable.. This testingmay include.any series of .
sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
The Frequency of 18 months is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.
This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
SR 3.8.1.20 This Surveillance demonstrates that the DGstarting independence -has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed.within the specified time when the DGs are started simultaneously.
The 1.0 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1.
This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs.
must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.
McGuire Units 1 and 2 B 3.8.1-27 Revision No. 111
AC Sources-Operating B 3.8.1 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
- 2. UFSAR, Chapter 8.
- 3. Regulatory Guide 1.9, Rev. 3, July 1993.
- 4. UFSAR, Chapter 6.
- 5. UFSAR, Chapter 15.
- 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
- 7. Regulatory Guide 1.93, Rev. 0, December 1974.
- 8. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.
- 10. Regulatory Guide 1.137, Rev. 1, October 1979.
- 11. IEEE Standard 308-1971.
- 12. Regulatory Guide 1.6, Rev. 0, March 1971.
- 13. Regulatory Guide 1.8.1, Rev. 1, January 1975.
McGuire Units 1 and 2 B 3.8.1-28 Revision No. 111